Press Room

Abstract: Drilling waste disposal through downhole hydraulic fracturing is often the preferred waste management option because it can achieve green operation and often has favorable economics. Most field situation comprise of injection in either dedicated well or in the annulus of an existing well. Containment of the disposed waste must be ensured and one of the questions in drilling waste injection operations is what the capacity of a disposal well or annular scheme is? The answer to this question depends on downhole waste storage mechanisms. It is evident from laboratory simulation studies and field operation experience that multiple fractures are created in drill cuttings injection (DCI) operations and the capacity of a disposal well is much larger than that estimated from single fracture simulations. More importantly, as more solids are injected into the disposal formation, the local stress is modified. Because of this change in local stress, fracture shapes and extents at the beginning of a DCI operation can be significantly different from the fracture shapes and extents at the end the operation. Modeling of this fracturing evolution process is necessary and essential to ensure the safe containment of the disposed waste and to estimate accurately the disposal capacity of a drilling waste disposal well. This paper presents a numerical algorithm for modeling the multiple fracturing and fracture evolution process during drill cuttings injection operations. Case studies show that the modeling results based on multiple fracturing have significant impacts on DCI operations engineering such as injection pressure requirement and disposal capacity. The results also provide insight into best practices for the containment of disposed waste, when injection can continue into a previous zone and when is there a need to inject into a different zone or when a new disposal well should be drilled. For the purpose of brevity, "disposal well" will be used to designate either a dedicated injector well or an annular injection scheme.

Abstract: The determination of maximum injection pressures is an important component of planning and permitting for deep well disposal of liquid wastes. In the United States, safe injection pressures are defined as those that do not initiate or propagate fractures. The maximum injection pressures are often based on the closure pressure at the wellbore; however, higher pressures can sometimes be demonstrated to be safe. This was the case during the recent preparation of a no-migration petition and permit applications for deep well injection at the BP Chemicals Inc. Lima, Ohio, facilities. In this case, a substantial database existed, which included core mechanical properties, in situ stress tests and transient pressure tests on a specially drilled stratigraphic test well, as well as about 20 years of injection flow and pressure history. These data were used to provide the required assurances to the regulatory agencies that injection over the closure pressure could be adequately defined. This analysis was complicated by the stress dependance of the injection formation permeability and the pluggage of the near wellbore region due to fines in the injection stream. This paper describes the database used and the analyses conducted to demonstrate that injection above closure pressure at BP Chemicals' facilities at Lima, Ohio, does not initiate or propagate fractures in the injection zone and that the injected fluids will be contained in the injection zone for at least 10,000 years.

Abstract: This paper summarizes the results obtained from a comprehensive, joint-industry field experiment designed to improve the understanding of the mechanics and modeling of the processes involved in the downhole injection of drill cuttings. The project was executed in three phases: drilling of an injection well and two observation wells (Phase 1); conducting more than 20 intermittent cuttings-slurry injections into each of two disposal formations while imaging the created fractures with surface and downhole tiltmeters and downhole accelerometers (Phase 2); and verifying the imaged fracture geometry with comprehensive deviated-well (4) coring and logging programs through the hydraulically fractured intervals (Phase 3). Drill cuttings disposal by downhole injection is an economic and environmentally friendly solution for oil and gas operations under zero-discharge requirements. Disposal injections have been applied in several areas around the world and at significant depths where they will not interfere with surface and subsurface potable water sources. The critical issue associated with this technology is the assurance that the cuttings are permanently and safely isolated in a cost-effective manner. The paper presents results that show that intermittent injections (allowing the fracture to close between injections) create multiple fractures within a disposal domain of limited extent. The paper also includes the conclusions of the project and an operational approach to promote the creation of a cuttings disposal domain. The approach introduces fundamental changes in the design of disposal injections, which until recently was based upon the design assumption that a large, single storage fracture was created by cuttings injections.

Abstract: The results of laboratory block fracturing experiments are presented which investigate the dominant fracturing mechanisms associated with drilling-waste injection operations. The tests include injection into reactive and competent shales, high permeability sands, and multi-layered formations of varying permeability. Specific details of proposed fracture mechanism have been confirmed or, where found to be inappropriate, these have been refuted.

Abstract: Cuttings and other drilling waste injection through downhole fracturing started in the late 1980s and by the early 1990s, drill cuttings injection was being performed worldwide as an economically sound and environmentally safe long-term solution for drilling and production waste management. Although drill cuttings injection has become the preferred drilling waste management option in many parts of the world, each situation is different and the biggest hurdle in applying this technology for drilling and production waste management in some countries is waste injection permit application either because the regulatory agencies have not established any permitting requirements and application procedures or because the E&P operators are not familiar with the application process. Although different regions or countries have different permitting requirements, many of the requirements are essentially the same. This paper presents a review and analysis of worldwide drilling waste injection permitting requirements. Common permitting requirements are given with application procedure guidelines. The operators can use the guidelines to prepare their permitting application, while the regulatory agencies may use the review and guidelines as a reference for establishing or streamlining their own drill cuttings injection permit application requirements and procedures.

Abstract: This article is a synopsis of paper SPE 72308, "Design Considerations in Drill Cuttings Reinjection Through Downhole Fracturing," by Ahmed S. Abou-Sayed, SPE, and Quanxin Guo, SPE, Advantek Intl., originally presented at the 2001 IADC/SPE Middle East Drilling Technology, Bahrain, 22-24 October.

Abstract: Performance and environmental assurance of cuttings injection programs require monitoring and periodic analysis of injection response. Such programs provide operational oversight and the ability to respond to changes in performance, providing for optimization of operating parameters to minimize potential negative impacts. Cuttings injection was implemented on a remote pad in the Cashiriari Field, located in a nature preserve in Camisea, Peru. CI was recognized as a technically and environmentally acceptable alternative for waste management in a location with extreme environmental sensitivity. Higher than anticipated injection pressures, indicative of regional and local stress regimes, required adjustments in operating parameters and expectations. Performance was contingent on successful inhibition of reactive clays in and around the target zones. Continuous monitoring of closure pressure and other trends associated with batch injection has made performance predictions possible. Monitoring operations have allowed for performance improvement and/or minimization of potential problems. The operation injected over 212,000 bbls of cuttings on the first pad and continues to be successful on the second pad through careful management of batch attributes and adaptation to operating realities. Assurance derived from such programs provides long term operational viability and social acceptance of cuttings injection as a safe means of waste management.

Abstract: Class I and Class II waste re-injection are the most important methods for disposing of fluid in North Dakota: in 2007, more than 96% of produced water were disposed of using underground injection, and by 2012 all produced water was being managed by underground injection. While Class II injection covers waste produced from most Exploration & Production (E&P) activities, Class I injection wells are used for disposing of a special class of industrial wastes, including waste generated by petroleum refining, metal production, chemical production, pharmaceutical production, commercial disposal, and food production. Non-hazardous industrial waste and Naturally Occurring Radioactive Materials (NORM) not associated with E&P can also be injected using Class I wells. In all cases, the primary concern for permitting and safe operations is to (1) predict the movement of the injected waste to ensure that it stays within pre-defined formations, and (2) ensure that pore-pressure increases caused by injection do not impact neighboring offset wells. Results from a geochemical study of the feasibility of disposal into the Dakota Sands (Inyan Kara formation) in North Dakota is being presented. Analyses were made using a compositional reservoir simulation (REVEAL) to predict the pore-pressure distribution, direction and movement of the injected fluid, as well as chemical reactions between formation brine/waste/formation rocks and the effect of these chemical reactions on formation injectivity and cap rock integrity. Forecasts indicate that for over 50 years of injection, the injected wastes will be completely trapped within the Dakota Sands (no fluid flow is expected to penetrate through the cap rock) and injection pressures are expected to remain well below the estimated fracture pressure. While the Inyan Kara formation is therefore a reasonable storage trap for industrial wastes, carbonate and sulfate scales may cause near wellbore formation damage and rising wellhead pressures which operators will need to address.

Abstract: Class I and Class II waste re-injection are the most important methods for disposing of fluid in North Dakota: in 2007, more than 96% of produced water were disposed of using underground injection, and by 2012 all produced water was being managed by underground injection. While Class II injection covers waste produced from most Exploration & Production (E&P) activities, Class I injection wells are used for disposing of a special class of industrial wastes, including waste generated by petroleum refining, metal production, chemical production, pharmaceutical production, commercial disposal, and food production. Non-hazardous industrial waste and Naturally Occurring Radioactive Materials (NORM) not associated with E&P can also be injected using Class I wells. In all cases, the primary concern for permitting and safe operations is to (1) predict the movement of the injected waste to ensure that it stays within pre-defined formations, and (2) ensure that pore-pressure increases caused by injection do not impact neighboring offset wells. Results from a geochemical study of the feasibility of disposal into the Dakota Sands (Inyan Kara formation) in North Dakota will be presented. Analyses were made using a compositional reservoir simulation (REVEAL) to predict the pore-pressure distribution, direction and movement of the injected fluid, as well as chemical reactions between formation brine/waste/formation rocks and the effect of these chemical reactions on formation injectivity and cap rock integrity. Forecasts indicate that over 50 years of injection the injected wastes will be completely trapped within the Dakota Sands (no fluid flow is expected to penetrate through the cap rock) and injection pressures are expected to remain well below the estimated fracture pressure. While the Inyan Kara formation is therefore a reasonable storage trap for industrial wastes, carbonate and sulfate scales may cause near wellbore formation damage and rising wellhead pressures which operators will need to address.

Abstract: Injecting oilfield waste into suitable receiving formations is an effective and environmentally acceptable method to dispose of drilling and production waste including cuttings, drilling fluids, produced water, emulsions and other produced waste. Traditionally, solid waste is degraded to less than 300 microns and suspended as water-based slurry containing 20% solid matter. Rheological properties are controlled so that the slurry can be injected, typically using triplex pumps, under high pressure (1000 to 5000 psi) through a casing annulus or tubular into hydraulic fractures. At locations, where injection pressures are within limits and the disposal well and domain may cope, or be benefitted with higher rates of injection, increases in the rate of disposal is beneficial to operations due to the increased efficiency allowing faster ROP's or faster evacuation of waste storage devices. This paper discusses the suitability and application of multistage centrifugal pumps for drilling waste injection and provides some data obtained during real time waste injection operations using multistage centrifugal pumps in parallel installation with traditionally used triplex pumps. Wear data in conjunction with engineering economic evaluation will be discussed. Slurry viscosity and particle size data will be presented to show the effect of pump shear on slurry properties and the implications for waste injection. A multistage centrifugal pump proved capable of pumping waste slurry continuously at relatively high rates for a limited trial period of time. A multistage centrifugal pump provides a continuous flow without the pulsation normally associated with using a reciprocating plunger-style pump and the need to have such pulsation dampened. Laboratory testing and real-time subsurface injection data at an offshore installation indicates that multistage horizontal centrifugal pumps may offer some benefits compared to traditional reciprocating triplex plunger pumps. Some operations requiring relatively high flow rates with flow media containing solids may benefit from implementation of this style pump providing the net power requirement and equivalent downhole pressure requirement are within the pump design range, and there is available footprint at the location. Oilfield waste can be disposed of in an environmentally responsible manner under zero-discharge conditions with the performance of the pump ensuring operational reliability and injection assurance. Operations on a global scale may benefit from this new application for multistage pumps. Decreased downtime together with slurry stability and controlled injection assures operational performance and cost effectiveness, enabling oilfield waste to be disposed in a safe, controlled and environmentally responsible manner.

Abstract: Performance and environmental assurance of cuttings injection programs require monitoring and periodic analysis of injection response. Such programs provide operational oversight and the ability to respond to changes in performance, providing for optimization of operating parameters to minimize potential negative impacts. Cuttings injection was implemented on a remote pad in the Cashiriari Field, located in a nature preserve in Camisea, Peru. CI was recognized as a technically and environmentally acceptable alternative for waste management in a location with extreme environmental sensitivity. Higher than anticipated injection pressures, indicative of regional and local stress regimes, required adjustments in operating parameters and expectations. Performance was contingent on successful inhibition of reactive clays in and around the target zones. Continuous monitoring of closure pressure and other trends associated with batch injection has made performance predictions possible. Monitoring operations have allowed for performance improvement and/or minimization of potential problems. The operation injected over 212,000 bbls of cuttings on the first pad and continues to be successful on the second pad through careful management of batch attributes and adaptation to operating realities. Assurance derived from such programs provides long term operational viability and social acceptance of cuttings injection as a safe means of waste management.

Abstract: The disposal domain concept is arguably accepted as the prevalent storage mechanism during the batch injection of drill cuttings. The disposal domain is best thought of as an elliptical realm surrounding the well. This phenomenon is well documented by field and laboratory observations and has been addressed in previous work. Most studies and field operations have centered around vertical or near vertical wells. Rarely have horizontal wells been designed for conversion to injectors or used for disposal and therefore, the effect of batch injection and the created disposal domain have not been addressed. The current paper will provide an integrated look at the fracturing process that occurred in a horizontal disposal well. The well is located in the Valhall Field, North Sea, offshore Norway. The well has multiple perforated intervals. The work will address a modified disposal domain concept as it applies to horizontal wells. The paper illustrates a history of the fracture nature (geometry and extent) and propagation across the various layers. Comparison of the field pressure history and the simulation results will be addressed. Further studies to address the effect of a workover carried out in the well, plug placement, are currently under way. These modifications will be addressed in a future paper.

Abstract: The disposal domain concept is arguably accepted as the prevalent storage mechanism during the batch injection of drill cuttings. The disposal domain is best thought of as an elliptical realm surrounding the well. This phenomenon is well documented by field and laboratory observations and has been addressed in previous work. Most studies and field operations have centered around vertical or near vertical wells. Rarely have horizontal wells been designed for conversion to injectors or used for disposal and therefore, the effect of batch injection and the created disposal domain have not been addressed. The current paper will provide an integrated look at the fracturing process that occurred in a horizontal disposal well. The well is located in the Valhall Field, North Sea, and offshore Norway. The well has multiple perforated intervals. The work will address a modified disposal domain concept as it applies to horizontal wells. The paper illustrates a history of the fracture nature (geometry and extent) and propagation across the various layers. Comparison of the field pressure history and the simulation results will be addressed.

Authors: K. S. Zaki, Advantek International; T. G.Kristiansen, BP Norway; A. S.Abou-Sayed, C. W. Summers, G. G. Wang, and M. D. Sarfare, Advantek International

Copyright 2005, Society of Petroleum Engineers

Abstract: Reinjection is one of the most important methods to dispose fluid associated with oil and natural gas production. Disposed fluids include produced water, hydraulic fracture flow back fluids, and drilling mud fluids. Several formation damage mechanisms are associated with the injection including damage due to filter cake formed at the formation face, bacteria activity, fluid incompatibility, free gas content, and clay activation. Fractured injection is typically preferred over matrix injection because a hydraulic fracture will enhance the well injectivity and extend the well life. In a given formation, the fracture dimensions change with different injection flow rates due to the change in injection pressures. Also, for a given flow rate, the skin factor varies with time due to the fracture propagation. In this study, well test and injection history data of a class II disposal well in south Texas were used to develop an equation that correlates the skin factor to the injection flow rate and injection time. The results show that the skin factor decreases with time logarithmically as the fracture propagates. At higher injection flow rates, the skin factor achieved is lower due to the larger fracture dimensions that are developed at higher injection flow rates. The equations developed in this study can be applied for any water injector after calibrating the required coefficients using injection step rate test (SRT) data.

Abstract: From the point-of-view of a solutions provider the wastewater treatment should be straight forward: once given the composition of the feed and the required composition of the effluent, today's technology allows formulating a set of solutions which best meets the operator's and the regulatory criteria. The problem with wastewater in the unconventional gas exploration and production operations is that there are large volumes to be handled and treated. To add complexity, composition varies for the same well in time and varies even more from area to area of development. Also, the requirements for the cleaned fluid vary from operator to operator and by region. Moreover, management of the water based fluids is under the pressure and scrutiny of various regulating agencies: public, privately, or governmentally run. All these constraints make the vetting of treatment methods and technologies to be a very dynamic and intensive process. Our findings during the process of formulating a set of solutions shows that a deep understanding of the problems, combined with close collaboration with the operators and regulators along with solid basic engineering practices are the key to success. Our experience would benefit the new developments in other unconventional exploration and production area in Asia by showing the steps that were undertaken to insure solutions are up to the highest standards. The process of finding and testing various waste water treatment technologies to formulate a flexible comprehensive set of methods will be described. Laboratory results of various samples of water will be presented as well as the challenges that were overcome for obtaining consistent, reliable analytical data. The oilfield tough requirement presented to new technologies translates as: rugged, flexible, mobile, and low cost.

Abstract: Injection pressure fall-off (PFO) test analysis has proven to be a reliable vehicle for understanding and evaluating well performance. Recently the methodology has been extended to the understanding of injectors. This paper presents an optimization model for analysis and interpretation of PFO tests for fractured water injectors. An elliptical composite flow model mathematically represents the fractured injector well. The optimization scheme couples the mathematical model of the well with a Genetic Algorithm (GA) to reach the final solution. The pressure transients representing the behavior of an injector a closing fracture and the discontinuity in fluid mobility are best developed in elliptical coordinates. The methodology derives the dimension of the induced fractures, formation permeability, fracture conductivity and fracture face skin. The current paper illustrates the solution methodology by showing the attained match for a West Africa offshore field case. The field case provides reasonable agreement for the fracture dimensions and characteristics as verified by other techniques. Genetic Algorithms are one of the most common artificial intelligence techniques for optimization. The reported solution is obtained by applying a GA with a non-linear least square error function as an objective function. A special penalty function, mutation, crossover probabilities, and stopping criterion are used to obtain the global minimum of the objective function. The test data analysis is done through type curve matching of the pressure and its derivative by minimizing the objective function to help determine the parameters that provide the best match between the field data and the presented novel fractured injector type curves.

Abstract: The oil business uses a large quantity of water during the drilling and completion of an unconventional gas well. In many of the shale plays each well needs in excess of 4 million gallons of water (100,000 bbl) during the drilling and completions operations. Water is a precious resource and many areas are faced with water shortages. Water shortages extend to almost all the traditional oil and gas producing areas in the United States including Colorado, California, Wyoming, Texas and Oklahoma. Also, the arid areas of Australia, The Middle East, and Africa see even more severe shortages of fresh water than in the United States. Moreover, in areas where water is not in short supply such as Indonesia, Malaysia, and the Eastern United States, discharge of high salt content water is problematic. In order to assure itself of adequate water for drilling and completion operations, the oil business needs to change the ways it has traditionally transacted its business. As stated above many drilling areas are faced with water shortages, whereas many other producing areas are faced with high disposal costs for frac flow back water and produced water. In many traditional production areas disposal of water is simple and usually inexpensive since there are numerous injection wells in these traditional production areas. However, in some of the new Shale plays the access to injection wells for disposal of produced water and frac flow back water is very limited. Part of the solution is to recycle the frac flow back water and the produced water for use as drilling fluid or for Frac Fluid. How clean does this water need to be for use as a drilling fluid or a frac fluid? What techniques are used to clean this water? How costly are the various techniques? These questions and others will be addressed in this paper.

Abstract: Re-Injection is one of the most important methods to dispose fluid associated with oil and natural gas production. Disposed fluids include produced water, hydraulic fracture flow back fluids, and drilling mud fluids. Several formation damage mechanisms are associated with the injection including damage due to filter cake formed at the formation face, bacteria activity, fluid incompatibility, free gas content, and clay activation. Fractured injection is typically preferred over matrix injection because a hydraulic fracture will enhance the well injectivity and extend the well life. In a given formation, the fracture dimensions change with different injection flow rates due to the change in injection pressures. Also, for a given flow rate, the skin factor varies with time due to the fracture propagation. In this study, well test and injection history data of a Class II disposal well in south Texas were used to develop an equation that correlates the skin factor to the injection flow rate and injection time. The results show that with time, the skin factor decreases until such a point at which the fracture dimensions are sufficient without further propagation to handle the injected water volume (stationary fracture). A constant skin factor is noted after this point. At higher injection flow rates, the constant skin factor achieved is lower because of the larger fracture dimensions developed at higher injection flow rates.

Abstract: Flow distribution plays an important role in Produced Water Re-Injection operations. This is especially true when the injection horizon contains isolated hydraulic units that are individually capable of accepting part of or the entire injection rate. The hydraulic units maybe separated by an impermeable barrier, shale, and/or have variations in the minimum horizontal stress. Under normal operating conditions fractures initiated in one or more of these units would not intersect or combine. The fracture growth becomes a coupled problem where growth in one hydraulic units is dependent on growth or retardation in other units. Retardation might be caused by solid and oil deposition in the fracture that would plug its tip and damage its faces. Plugging would decrease available fracture length for leakoff below the actual total length of the fracture. Such scenarios become difficult to control if not initially planned or designed for and can lead to undesirable effects such as inefficient sweep or uncontrolled fracture growth. In the following discussion the design and monitoring criteria for such problems will be addressed. We will review some available tools and prominent parameters and/or variables that affect this behavior both from a time dependent and independent point of view. Particular attention will be placed on the damage mechanisms, total suspended solids (TSS) and oil in water (OIW), and their effects on altering the injection rate distribution as a progressive time dependent phenomena. Finally, two scenarios will be presented, as practical examples of field cases where flow partitioning issues presented a particular concern as a result of inherent reservoir properties.

Abstract: Produced water re-injection (PWRI) is often the safest and most economical method for disposal of produced water in the oil industry. Two key issues that affect the management of PWRI are the formation damage and the constrained pumping pressure at the wellhead. A simulator was developed to handle the design of single-zone or multi-zone water injection in multilayered reservoirs. The simulator can accommodate both vertical and horizontal wells operated under matrix and/or fractured regimes. It is also able to account for the impact of formation damage and user-defined wellhead pressure constraints. Results obtained from the simulator showed good agreement with known injection behaviors. For vertical wells, injection conformance depends on KH (permeability-thickness) and the minimum horizontal stress; in the case of multi-fractured horizontal wells, the outermost fractures (those near the tip and the heel of the horizontal well) are longer than the fractures in the middle. Lastly, by constraining the maximum allowable surface pressure, frictional pressure drops in both the wellbore and fracture cause the injection rate to decline, which in turn affects both the fracture geometry and the maximum disposal volumes.

This paper was prepared for presentation at the 1999 SPE Asia PacificImproved Oil Recovery Conference held in Kuala Lumpur, Malaysia, 25-26 October1999.

Abstract: A 30 day waterflooding test in which seawater was injected into two production zones (A and B) of an oil producing limestone reservoir is analyzed. During testing the flow rates were varied to maintain constant tubing head pressure. Injection rates were recorded for three levels of constant tubing head pressures (THP): initial (THP = 990 psig), intermediate (THP = 1240 psig), and final (THP = 1490 psig). The purpose of the analysis was to detect the possible occurrence of a fracture. A radial fluid possible occurrence of a fracture. A radial fluid flow technique was utilized to analyze the pressure-injection behavior. The analyses disclosed a pressure-injection behavior. The analyses disclosed a change in the formation's ability to transmit fluids. Rock mechanics analyses were utilized to quantify the changes in in situ stress due to water flooding effects (i.e. pore pressure buildup and temperature decrease). The later analysis disclosed that the bottomhole fluid pressures exceeded the modified minimum in situ stresses at the intermediate and final pressure levels. Both, the increase in fluid transmissibility and the bottomhole fluid pressure rise above the modified minimum in situ stress indicated the occurrence of fracture. A possible fracture geometry was obtained by means of 2-D and 3-D hydraulic fracturing simulators.

Abstract: Produced water re-injection (PWRI) is often the safest and most economical method for disposal of produced water in the oil industry. Two key issues that affect the management of PWRI are the formation damage and the constrained pumping pressure at the wellhead. A simulator was developed to handle the design of single-zone or multi-zone water injection in multi-layered reservoirs. The simulator can accommodate both vertical and horizontal wells operated under matrix and/or fractured regimes. It is also able to account for the impact of formation damage and user-defined wellhead pressure constraints. Results obtained from the simulator showed good agreement with known injection behaviors. For vertical wells, injection conformance depends on KH (permeability-thickness) and the minimum horizontal stress; in the case of multi-fractured horizontal wells, the outermost fractures (those near the tip and the heel of the horizontal well) are longer than the fractures in the middle. Lastly, by constraining the maximum allowable surface pressure, frictional pressure drops in both the wellbore and fracture cause the injection rate to decline, which in turn affects both the fracture geometry and the maximum disposal volumes.

Abstract: Key factors in framing a produced water management (PWM) strategy include a company's internal and external environments, technology and business drivers. Emerging trends for establishing an environment-friendly PWM position can comprise these declared policies:

• Move toward zero emission
• No discharge to surface or seas
• Waste-to-Value conversion
• Incremental and progressive separation
• Pro-activity to influence partners, regulators and environmental laws

This paper covers the technical approaches for addressing production, separation, and disposal/injection segments of water injection and reservoir water flooding and the basis for selecting strategy components and PWM actions. Best practices result from both comprehensive assessments of current PWM tools and insights from a decade-long, joint industry project (JIP) on produced water re-injection (PWRI).

Abstract: This paper provides a comprehensive and critical review of external filter cake formation during dynamic (cross-flow) filtration with main focus on petroleum engineering applications. Numerous researches have been done during the last several decades to investigate the cake buildup mechanisms, structure and effects of various parameters on cake properties, flux decline and stabilisation. However, a consistent hypothesis to explain the main cake buildup mechanisms and structure has not been devised yet due to numerous laboratory and field observations that can be attributed to different physics mechanisms.

Authors: Zaki, K., Sarfare, M.D., Abou-Sayed, A.S.

Copyright 2006, Society of Petroleum Engineers

Abstract: The objective in Hydraulic Fracturing is to increase well productivity and enhance or accelerate hydrocarbon recovery. Yet in soft formations, where hydraulic fracturing provides the secondary benefit of sand control, FracPack operations may result in adverse effects. These effects are more prominent in Gulf of Mexico (GOM) deepwater fields, where sands are over-pressured and highly compactive. Porosity loss around the fractured well normally occurs during FracPacks. This paper addresses this issue and quantifies the permeability loss in FracPack treatments.

Authors: Sarfare, M., Zaki, K., Abou-Sayed, A.S.

Copyright2006, Society of Petroleum Engineers

Abstract: Traditionally, hydraulic fracturing simulations have been based on elastic theories. Although this is adequate for hard rocks the fracture geometry predictions fall short when applied to fracturing soft rocks that are at incipient plasticity, or that are prone to compaction. These phenomena are usually encountered during fracturing for sand control, FracPacks and disposal of slurries and drilling cuttings in soft layers. The capacity of the created fracture to store solids, the conditions of the rock strength near the fracture faces and the near well/fracture rock permeability are all highly impacted by the rock compaction during fracture propagation.

Authors: Zaki, K.; Meng, F.; Wang, G. and Abou-Sayed, A.S.

Abstract: The widespread use of FracPack technology in deepwater reservoirs has been a growing practice. Its purpose is sand control and well stimulation. To-date, field applications and fracture treatments have been designed using traditional hydraulic fracturing simulators that apply LEFM theories. While this is adequate for hard rocks (e.g., tight gas formations), the fracture geometry predictions fall short when applied to fracturing soft rocks. Soft rocks are normally at incipient plasticity and, hence, are prone to compaction.

Authors: Abou-Sayed, A.S., Zaki, K., Wang, G., Meng, F., and Sarfare, M., Advantek International Corp.

Copyright 2004, Society of Petroleum Engineers

Abstract: Elastic parameters play a key role in managing the drilling and production operations. Determination of the elastic parameters is very important to avoid the hazards associated with the drilling operations, well placement, wellbore instability, completion design and also to maximize the reservoir productivity. A continuous core sample is required to be able to obtain a complete profile of the elastic parameters through the required formation. This operation is time-consuming and extremely expensive. The scope of this paper is to build an advanced and accurate model to predict the static Young’s modulus using artificial intelligence techniques based on the wireline logs (bulk density, compressional time, and shear time). More than 600 measured core data points from different fields were used to build the AI models. The obtained results showed that ANN is the best AI technique for estimating the static Young’s modulus with high accuracy [R2 was 0.92 and the average absolute percentage error (AAPE) was 5.3%] as compared with ANFIS and SVM. For the first time, an empirical correlation based on the weights and biases of the optimized ANN model was developed to determine the static Young’s modulus. The developed correlation outperformed the published correlations for static Young’s modulus prediction. The developed correlation enhanced the accuracy of predicting the static Young’s modulus. (R2 was 0.96 and AAPE was 6.2%.) The developed empirical correlation can help geomechanical engineers determine the static Young’s modulus where laboratory core samples are not available.

Abstract: Stress reorientation is an important issue for the cuttings injection batching, refracturing design and stimulation candidate well selection. Long term production/injection causes the principal stresses to reorient. Temperature differences and pore pressure differentials induce thermal elastic stress and poroelastic stresses. These induced stresses are the fundamental reasons for the reorientation of the stress field. A model and numerical scheme are developed to study the effects of thermal differentials and pressure differentialss on stress reorientation. The model couples thermal diffusion and convection with hydraulic diffusion to obtain the temperature distribution reflecting the cumulative impact. The effective poro-elastic and thermo-elastic stresses result from the 1-D displacement equilibrium equations in a radial system. The 3-D in-situ analytical effective stress is superimposed on the 1-D solution. Application of this methodology simplifies the modeling of the 3-D stresses in a deviated borehole. The method makes it practical to obtain the stress distribution at any given injection/production time. The thermal stress and poro-elastic stress effects on the stress reorientation are compared and evaluated. Field examples are presented to show that in some cases the thermal stresses play an important role on stress reorientation. The quantified results of the model will give guidance on fracture treatments and well plans during injector or producer construction.

Abstract: There has been substantial recent progress in coupling geomechanical effects to reservoir response, thus dramatically improving representation of the consequences of rock response to pressure changes. New reserves have been identified from compaction. Injection geomechanics has gained an increase in interest due to its impact on the reservoir, faults and well hardware. Changes in transmissibility are now seriously implemented in reservoir engineering tools with more attention directed at the presence of compaction and dilatant bands around producers or injectors. Efforts are progressing to ensure adequate coupling between the local effects of the rock deformation near the wellbore, as well as along faults or bedding planes, and the evolving stresses and deformation in the reservoir. This paper attempts to discuss current gaps in understanding the intricacies and details of coupling farfield deformation to well completion. Examples are shown where reservoir compaction or dilatancy is explicitly coupled to near-wellbore behavior, with specific application for assessing well performance and survivability. The analyses can use reservoir simulations coupled with analytical predictions of stresses and deformations in individual simulator blocks. The predicted stresses and deformations form the boundary conditions for finite element modeling that can focus in on the details around the completion itself. This is in contrast to the current approaches that use explicit coupling of pressure and deformation in complete massive finite element representations, with refined gridding around the completion.

Abstract: The ongoing Prudhoe Bay Grind and Inject (GNI) program began in the mid 1990?s. State and Federal Environmental regulations require the operator to assure the injected material not be allowed to migrate to groundwater aquifer zones or to the surface. Sensitive fracture modeling and annual surveillance activities have been conducted to ensure the integrity of the process. A recent extensive technical review of the field?s collected information, injection simulation results and well testing data was conducted to evaluate the containment of the injected slurry. The current paper discusses the results of engineering simulation and field monitoring efforts within the perspective of a geomechanics review to verify the injected slurry extent. Novel interpretations of pressure records along with new simulation results are presented. Analysis of the waste domain simulation, based on fracture propagation in compactable (soft) rocks and well testing data, confirm that the fracture domain is confined in the intended injection zone. This paper will also compare the results of successive fracture domain simulations to the results of annual well tests over the last 5 years. Finally, the applicability of other potential means of disposal domain monitoring and diagnostic tools such as surface and downhole tiltmeters, micro seismic diagnostic, and tracers, are assessed from a geomechanics perspective.

Abstract: The disposal domain concept is arguably accepted as the prevalent storage mechanism during the batch injection of drill cuttings. The disposal domain is best thought of as an elliptical realm surrounding the well. This phenomenon is well documented by field and laboratory observations and has been addressed in previous work. Most studies and field operations have centered around vertical or near vertical wells. Rarely have horizontal wells been designed for conversion to injectors or used for disposal and therefore, the effect of batch injection and the created disposal domain have not been addressed. The current paper will provide an integrated look at the fracturing process that occurred in a horizontal disposal well. The well is located in the Valhall Field, North Sea, offshore Norway. The well has multiple perforated intervals. The work will address a modified disposal domain concept as it applies to horizontal wells. The paper illustrates a history of the fracture nature (geometry and extent) and propagation across the various layers. Comparison of the field pressure history and the simulation results will be addressed. Further studies to address the effect of a workover carried out in the well, plug placement, are currently under way. These modifications will be addressed in a future paper.

Abstract: Stress reorientation is an important issue for the refracturing design and candidate well design. The long term production/injection causes the stresses to reorient. The temperature differential and pressure differential induced thermal elastic stress and poroelastic stresses are the fundamental reasons for the stress to reorient. A model and numerical scheme are developed to study the effects of thermal differential and pressure differential on stress reorientation. In the model, thermal diffusion and convection is coupled with hydraulic diffusion to obtain the temperature distribution reflecting the cumulative impact. The effective poro-elastic and thermo-elastic stresses are obtained from 1-D displacement equilibrium equation in a radial system. The 3-D in-situ analytical effective stress is superimposed on the 1-D solution. By applying this methodology the 3-D deviated borehole stress model is greatly simplified. The method makes it practical to obtain the stress distribution at any given injection/production time. The thermal stress, poro-elastic stress effects on the stress reorientation are compared and evaluated. Field examples are presented and show that in some cases thermal plays an important role on stress reorientation. The quantified results of the model will give guidance on the fracture treatments and well plan.

Abstract: Drilling instability is always one of the major challenges to drilling engineers. The temperature differential and pressure differential affect the borehole instability by altering the stress concentration at near wellbore region through poro-elastic and thermal elastic stresses. The temperature gradient and pressure gradient between the drilling fluid and formation change not only from conduction and convection, but also from interacting to each other. In low mobility formation such as shale, the thermo-induced pore pressure is important while in high mobility formation, the pressure effect on the temperature is not negligible. Furthermore, the imbalance in chemical potentials between the formation pore fluid and wellbore drilling fluid will cause the solvent and solutes to diffuse and transport. This will alter the fluid pressure due to chemical osmosis pressure. In this paper, a fully coupled borehole stability model is proposed including thermal, pore, chemical effect. In the model, not only pressure, heat conduction and convection are included, but also the interaction of pressure and heat are incorporated. The model is solved by superimposing method and finite difference method which otherwise is impossible to be obtained from analytical solution.

Abstract: The estimation of the in situ stresses is very crucial in oil and gas industry applications. Prior knowledge of the in situ stresses is essential in the design of hydraulic fracturing operations in conventional and unconventional reservoirs. The fracture propagation and fracture mapping are strong functions of the values and directions of the in situ stresses. Other applications such as drilling require the knowledge of the in situ stresses to avoid the wellbore instability problems. The estimation of the in situ stresses requires the knowledge of the Static Young’s modulus of the rock. Young’s modulus can be determined using expensive techniques by measuring the Young’s modulus on actual cores in the laboratory. The laboratory values are then used to correlate the dynamic values derived from the logs. Several correlations were introduced in the literature, but those correlations were very specific and when applied to different cases they gave very high errors and were limited to relating the dynamic Young’ modulus with the log data. The objective of this paper is to develop an accurate and robust correlation for static Young’s modulus to be estimated directly from log data without the need for core measurements. Multiple regression analysis was performed on actual core and log data using 600 data points to develop the new correlations. The static Young’s modulus was found to be a strong function on three log parameters, namely compressional transit time, shear transit time, and bulk density. The new correlation was tested for different cases with different lithology such as calcite, dolomite, and sandstone. It gave good match to the measured data in the laboratory which indicates the accuracy and robustness of this correlation. In addition, it outperformed all correlations from the literature in predicting the static Young’s modulus. It will also help in saving time as well as cost because only the available log data are used in the prediction.

Abstract: Unconfined compressive strength (UCS) is the key parameter to; estimate the in situ stresses of the rock, alleviate drilling problems, design optimal fracture geometry and to predict optimum mud weight. Retrieving reservoir rock samples throughout the depth of the reservoir section and performing laboratory tests on them are extremely expensive as well as time consuming. Therefore, mostly UCS predicted from empirical correlations. Most of the empirical correlations for UCS prediction are based on elastic parameters or on compressional wave velocity. These correlations were developed using linear or non-linear regression techniques. This paper presents a rigorous empirical correlation based on the weights and biases of Artificial Neural Network to predict UCS. The testing of new correlation on real field data gave a less error between actual and predicted data, suggesting that the proposed correlation is very robust and accurate. Therefore, the developed correlation can serve as handy tool to help geo-mechanical engineers in order to determine the UCS.

Abstract: Compressional (P-wave) and shear (S-wave) velocities are used to estimate the dynamic geomechanical properties including: Poisson’s ratio, Young’s modulus, and Lamé parameters. These parameters are mainly used in estimating the static properties of the formation rocks as well as the in situ stresses. The sonic logs are not always available, epically for old wellbores. Also, in several occasions when the sonic logs are available, missing sections found in the well logs might affect the analysis results. To the authors’ knowledge, there is no single straightforward correlation that can be used to accurately estimate both P- and S-wave travel times directly from the well log data. Most of the existing correlations use the P-wave velocity to measure the S-wave velocity. The main purpose of this study is to develop accurate and simple empirical models using wireline log data (bulk density, gamma ray, and neutron porosity) to predict the sonic travel times (P-wave and S-wave). These wireline logs are slandered wireline log data that are commonly recorded in most of the wells. Three robust artificial intelligence techniques, namely: support vector machine (SVM), artificial neural network (ANN), and adaptive neurofuzzy interference systems (ANFIS), were employed and compared based on their prediction performance. Ultimately, using the weights and biases of optimized ANN model, a simple generalized empirical correlation is derived that can be used without the need of costly commercial software’s to run the AI models. The obtained results showed that ANN, ANFIS, and SVM can be used to estimate P-wave and S-wave travel times. ANN outperformed the ANFIS and SVM by yielding the lowest average absolute percentage error (AAPE) and the highest coefficient of determination (R2) for predicting P-wave and S-wave travel times. ANN model could predict the P-wave and S-wave travel times from wireline log data with high accuracy giving R2 of 0.98 when compared to actual field data. In addition, the developed empirical correlations prediction completely matched the ANNs prediction. The AAPE of the predicted P and S-waves travel times was less than 5%. The developed correlations are very accurate and can help geomechanical engineers to determine the dynamic geomechanical properties (Poisson’s ratio and Young’s modulus) and propose any operation in case where sonic logs are missing.

Abstract: Static Poisson’s ratio plays a vital role in calculating the minimum and maximum horizontal stresses which are required to alleviate the risks associated with the drilling and production operations. Incorrect estimation of Static Poisson’s ratio may wrongly lead to inappropriate field development plans which consequently result in heavy investment decisions. Static Poisson’s ratio can be determined by retrieving cores throughout the depth of the reservoir section and performing laboratory tests, which are extremely expensive as well as time consuming. The objective of this paper is to develop a robust and an accurate model for estimating static Poisson’s ratio based on 610 core sample measurements and their corresponding wireline logs data using artificial neural network. The obtained results showed that the developed ANN model was able to predict the static Poisson’s ratio based on log data; bulk density, compressional time, and shear time. The developed ANN model can be used to estimate static Poisson’s ratio with high accuracy; the correlation coefficient was 0.98 and the average absolute error was 1.3%. In the absence of core data, the developed technique will help engineers to estimate a continuous profile of the static Poisson’s ratio and hence reduce the overall cost of the well.

Abstract: Various geomechanical-modeling approaches, which cover a wide range of techniques and complexity, have been developed to assess the stability of a borehole and/or the integrity of well casing. The ability to confidently use these models can be limited, however, because they generally do not allow the model user to consider the "real-world" variability of the input parameters defined in the models. Often, these geomechanical models do not adequately accommodate the innate variability of the rock properties (mechanical and petrophysical) of the target reservoirs. Consequently, this deterministic approach too often results in uncertainty about the "correct" value of a critical parameter to use and insecurity in the model results. Decisions based on these results can later, not surprisingly, be found to be incorrect. Model users attempting to overcome the limitations noted above have tried various techniques. Subjective estimation, arbitrary "minimums", grading techniques, and stepwise estimation have all been commonly used. Recently, more powerful techniques such as Monte Carlo simulation and decision analysis have come into popular use. Over the past decade these two techniques have been extensively used in the petroleum industry to evaluate and solve a wide range of analytical problems in reservoir engineering and the geosciences. In this paper, the application of these techniques to a number of generalized geomechanical problems will be illustrated. A Monte Carlo simulation enables the user to identify, measure or estimate, and evaluate uncertainties in the problems being analyzed. The simulation models the random behavior of the input variables much like in a game of chance. That is, the variables have an uncertain value within a known range for any particular time or event. Numerical model and software packages are developed based on the Green's function for a nucleus of strain in the reservoir. The model is coupled with reservoir simulations to evaluate pressure maintenance and reservoir development schedule effect on casing integrity, fault stability via sensitivity studies. The geomechanics solutions would be coupled with both commercial or in-house developed reservoir simulators. The results of multiple simulations, done to determine the most likely outcome of various wellbore solution options, are reported in the current paper.

Abstract: An analysis of data of borehole breakouts as an indication of orientation of in-situ stresses is presented. Wellbores drilled in Alaska and Colorado provided data for this investigation. Two field cases illustrating borehole breakouts at opposing failure directions are discussed. The first case refers to an offshore well drilled in the Gulf of Alaska. The failure zone is predicted to take place centered on the diameter in the direction of the least horizontal principal stress. The second case refers to the failure in a coal seam in a wellbore drilled in the Piceance Basin (Colorado). The failure mode was located normal to the direction of the least horizontal principal stress. Both failures can be explained by the von Mises failure criteria.

Abstract: The Ugnu deposit, located on the North Slope of Alaska, contains more than 6 billion bbl [954 X 106 m 3] of oil in place (OIP) in the Kuparuk area. The oil has been biodegraded. At reservoir temperature, the dead-oil viscosity varies from 100,000 to 10,000,000 cp [100 to 10 000 Pa·s]. The paper provides reservoir and geological descriptions of the resource and discusses the key aspects affecting development. These aspects include high-temperature formation damage, the projected production performance, and the design considerations for injecting steam through a thick permafrost interval.

Although hydrochloric acid (HCl) has been used for more than 60 years in the matrix acidizing treatment for carbonate reservoirs, the process is still as much art as science. The modeling of the acidizing processes in carbonate formations is complex because of formation heterogeneity and the use of multi-fluid in the treating processes. Prediction of the acid treatment parameters and design of the acid treatment program in the carbonate rock is the main goal of the present study. A computer simulation program using Fortran 77 was developed to predict the design parameters and simulate the performance of the acidizing treatment in the carbonate rocks. The developed simulator can be used to predict the optimum acid rate which gives the best treatment results, determine the surface and bottom-hole pressures during carbonate rock acidizing treatment, determine the distribution of the treatment fluids between formation zones, calculate the wormhole length formed in the formation, estimate the improvement in the formation skin factor due to formation treatment, and evaluate the formation productivity enhancement. The developed simulator can be used for all types of carbonates using multi-zone and multi-stage pumping. The developed simulator was validated and applied to several case studies. This paper presents the structure of the developed simulator and its application to a case study of Arab-D reservoir Saudi Arabia. The results show a good match with the actual recorded data. This work presents also a comparison between the results of the developed simulator and the results of the commercial matrix simulator (JIP - Joint Industry Project simulator) that is actually used in the industry.

Abstract: Flow experiments were performed on a ten-inch diameter by fifteen-inch long thick-walled cylindrical sample of poorly consolidated sandstone, with a 1.25-inch diameter borehole.The purpose was to evaluate the effect of changing stress regimes on near-wellbore permeability and liner loading. A one-inch diameter screened liner was installed in the wellbore to preclude sand production. The liner was instrumented with strain gages, in order to determine stresses resulting from borehole deformation during production.The cylindrical sample was instrumented with pore pressure probes, placed at different distances from the wellbore, in order to assess variation in formation permeability with evolving effective confining stresses and production regimes.The major conclusions of this experiment are as follows: 1. If sand ablation does not occur and if an adequate annular space exists between the liner and the wellbore, load transfer to the liner is mitigated. If sand ablates and fills the annular gap, the complexity of the load transfer mechanism increases dramatically.This has been addressed elsewhere(Abou-Sayed et al., 1995; Willson and Abou-Sayed, 1998). 2. Apparent dilatant behavior in the near-wellbore region leads topermeability increase. 3. An intermediate interval experiences a reduction in permeability, due tostress transfer, following yielding of the inner zone, adjacent to the wellbore.

Abstract: Terra Tek performed laboratory tests in support of a DOE/Gas Producing Enterprise (GPE) joint project for stimulation of the Wasatch and Mesa Verde sandstone in Natural Buttes Well No. 21 located in the Bitter Creek field, Uintah County, Utah. Massive hydraulic fractures were planned to stimulate gas production. Laboratory test data analyses were directed towards optimizing three separate fractures, one in the Wasatch pay sand and one each in two different pay sands in the Mesa Verde formation. Based on material properties determined the fractures initiated in each pay formation will migrate out of zone. There is a high probability that the fracture will move downward when fracturing the Lower Mesa Verde formation. Fracture lengths, therefore, will be limited by proximity to neighboring aquifer. Candidate fracturing fluids imposed a high degree of matrix permeability reduction. However, upon clean-up matrix permeability recovered to a degree that no noticeable reduction is well productivity is expected. On the other hand, all fracture fluids indelibly reduced fracture conductivity. The least damaged fracture exhibited a conductivity of 104 md-ft and the highest damage resulted in a conductivity of 16 md-ft. Fracturing fluid residue was mainly responsible for the loss in fracture conductivity.

Abstract: Various geomechanical-modeling approaches, which cover a wide range of techniques and complexity, have been developed to assess the stability of a borehole and/or the integrity of well casing. The ability to confidently use these models can be limited, however, because they generally do not allow the model user to consider the "real-world" variability of the input parameters defined in the models. Often, these geomechanical models do not adequately accommodate the innate variability of the rock properties (mechanical and petrophysical) of the target reservoirs. Consequently, this deterministic approach too often results in uncertainty about the "correct" value of a critical parameter to use and insecurity in the model results. Decisions based on these results can later, not surprisingly, be found to be incorrect. Model users attempting to overcome the limitations noted above have tried various techniques. Subjective estimation, arbitrary "minimums", grading techniques, and stepwise estimation have all been commonly used.

Abstract: In this work the effect of sample size on the compressive strength of Cedar City quartz diorite is investigated. Results are reported for laboratory unconfined compression tests on cylindrical samples, 25 mm (1 in) to 146 mm (5.77 in) in diameter with 1:2.5 diameter to length ratio. Stiffness compensators were inserted in the machine to simulate the in situ load frame stiffness of previous field tests. Each sample was strain-gaged at three positions around the cross section. Nonuniform sample deformations were observed during the tests. The maximum strain in each sample was calculated and a maximum stress was evaluated based on combined compression and bending loading conditions. The results indicate a slight decrease in nominal compressive strength, sc, with an increase in sample diameter, D, given by the equation(mathematical equation)(available in full paper) Furthermore, the effect of load frame stiffness on the measured strength is negligible. Weathering effects, on the other hand, seem to cause a reduction in the strength of the material. Finally, a maximum strain failure criterion for the tested rock was found to fit most of the data obtained in the present investigation and in previous work [Pratt, et al. (1975)]. The maximum allowable compressive strain is 0.74 percent with a standard deviation of .07 percent.

Abstract: The role of in-situ stresses in controlling hydraulic-fracture geometry and extent has been widely recognized. This paper describes the results and applications of several research programs carried out over the past few years to optimize the design of hydraulic-fracture stimulation treatments using information pertaining to in-situ stress action within the reservoir. Begun as fracture-mechanics-based theoretical studies of propagation and containment of hydraulically induced fractures, these programs have grown into full-scale field demonstrations of the deduced principles. A review is provided of field-measured in-situ stresses in the pay and confining formations. The existence of in-situ stress contrast between the pay zone and the bounding layers has been demonstrated in these field demonstrations. Furthermore, the results also showed the significant role of the in-situ contrasts in fracture containment. Unfortunately, however, great variability in the stress contrast from site to site has been observed. The field programs have been performed in both openhole and cased wells. Laboratory studies of hydraulically fractured large block samples have been carried out. Cubic samples up to 3.3 ft per side were subjected to triaxial stresses as high as 2,175 psi. The results of these tests have been used to support the field efforts.

Abstract: The high cost of offshore drilling and the safety aspects of penetrating depleted reservoirs bring borehole stability issues to the forefront of resource development. Drilling in deepwater fields, depleted reservoirs and/or low stress environments requires careful assessment of mud weights. Higher collapse pressures combined with lower fracture gradients limit or eliminate mud weight windows and lead to tight holes or lost circulation. Extended-reach wells require minimization of the number of casing shoes to reach the deeper targets. The need for long, open sections while drilling imposes restrictions on mud windows. Borehole strengthening has become the most effective method to address borehole stability in such circumstances.

Abstract: The paper discusses the impact of reservoir production on wellbore integrity and survivability when the compacting reservoir behaves as a deformable permeable body. The discussion is carried out using results of a numerical geomechanics model developed for estimating reservoir compaction, the subsequent surface/mudline subsidence; and the displacements, stresses and strains along the wellbore trajectories. The model has the unique aspect of efficiently coupling rock geomechanics with the actual reservoir simulation results. The input data include such relevant reservoir properties as pore volume compressibility, net-to-gross, porosity; corner point coordinates of each block from the reservoir simulator (the simulator blocks are identical to the elements used for the geomechanics model), wellbore trajectories and rock properties of the overburden. The deformation, stress and strains in the rock and along the well casings are evaluated at distinct time intervals. The initial, intermediate and final reservoir pressure profiles calculated by the reservoir simulator are central to the calculations. The model also has explicit analytical relationships that can be used to represent distinct variations in overburden lithologies.

Abstract: Compaction-induced casing damage, particularly adjacent to reservoir boundaries, has been observed in many fields. As part of mitigation planning for potential casing collapse due to reservoir compaction, expensive numerical models are often employed to quantitatively assess casing strain under simulated reservoir conditions. In order to simplify casing deformation analysis and reduce analysis time, the current study was initiated to quantify the effects of depletion magnitude, rock compressibility, borehole orientation, casing diameter-to-thickness ratio (D/t ratio) and grade on compaction-induced casing deformation using finite element modelling (FEM). The model results allowed an empirical equation to be derived to predict casing strain that is sufficiently accurate for engineering applications. The objective of the study was achieved by building a series of 3D FEM models to systematically simulate the deformation of casings cemented perfectly within a horizontal reservoir that underwent up to 8.3% compaction due to depletion. To capture the pattern of casing strain variation adjacent to the reservoir boundaries, the simulations were run over a range of borehole deviations (0°, 22.5°, 50°,67.5° and 90°). For each borehole deviation, casing D/t ratios of 8.14, 19.17 and 32.67 and grades of 40 ksi, 90 ksi and 135 ksi were defined to evaluate their impact on casing strain variations.

Abstract: Thermal and mechanical rock properties were evaluated with special laboratory tests and logs to analyze a Steam Assisted Gravity Drainage (SAGD) project by MARAVEN S.A. (now part of PDVSA Exploración y Producción) in the heavy oil Tía Juana field on the eastern side of Lake Maracaibo, Venezuela. This SAGD project is the first application of this technology in Venezuela and consisted of two parallel horizontal wells on top of each other where steam is injected in the upper well and oil is produced in the lower well.

Authors: Abou-Sayed, A.S., Guo, Q., Vasquez, A.R., Sanchez, M.S., Portillo, F., Poquioma, W., Blundun, M., and Mendoza, H.

Copyright 1999, Society of Petroleum Engineers

Abstract: This paper outlines a solution approach for evaluating the stability of casing and faults due to reservoir compaction. Firstly, a geomechanics model is presented for the evaluation of casing failure due to reservoir compaction. Secondly, a three dimensional finite element analysis is coupled with the developed geomechanics compaction model for the detailed casing failure analysis. Deformations and stresses are determined on a cylindrical surface surrounding the length of the newly drilled or completed wellbore in the regions of interest. This cylindrical surface is sufficiently remote from the wellbore so that the wellbore has no or little influence on the stresses and displacements due to the reservoir compaction on this surface. The calculated displacements on the cylindrical surface are then used as boundary conditions for a focused near-wellbore stress and strain analysis using finite element technology. This hybrid analysis affords evaluating the near wellbore details that are often glossed over with a fastly compacted solution not requiring multimillion FEA cells. Yet, it preserves the fine details around the wellbore and allows for incorporating fault loading and macro influences of geologic structures and reservoir extent. It preserves the material balance and does not alter the pressure volume relationship in the reservoir void space. Interface elements can account for the slippage between the casing and the cement and between the formation rock and the cement. Field cases are presented for both the geomechanics model and hybrid finite element model.

Authors: Abou-Sayed, A.S., F. Meng, and G. Wang, Advantek International Corporation

Abstract: Various geomechanical-modeling approaches, which cover a wide range of techniques and complexity, have been developed to assess the stability of a borehole and/or the integrity of well casing. The ability to confidently use these models can be limited, however, because they generally do not allow the model user to consider the "real-world" variability of the input parameters defined in the models. Often, these geomechanical models do not adequately accommodate the innate variability of the rock properties (mechanical and petrophysical) of the target reservoirs. Consequently, this deterministic approach too often results in uncertainty about the "correct" value of a critical parameter to use and insecurity in the model results. Decisions based on these results can later, not surprisingly, be found to be incorrect. Model users attempting to overcome the limitations noted above have tried various techniques. Subjective estimation, arbitrary "minimums", grading techniques, and stepwise estimation have all been commonly used.

Authors: Abou-Sayed, A.S., Guo, Q., and Meng, F., Advantek International Corporation

Copyright 2004, Society of Petroleum Engineers

Abstract: Subsurface fractured injection (sometimes called cuttings re-injection, drill cuttings injection, or slurry injection) has been proven over the past decades to be the safest, most efficient, and the lowest-cost technology for disposal of certain kinds of oil and gas waste. This technology involves creating a hydraulic fracture in a subsurface injection formation followed by an intermittent process of pumping the slurrified waste into the fracture. The objective of this study is to investigate the impact of changing the rheological properties of the slurrified waste on the hydraulic fracture geometry. The investigation was conducted in two main steps: first, using the geophysical information a geotechnical earth model was built to estimate the mechanical properties of different subsurface formations. This allowed the selection of a porous/permeable injection formation which is over-laid and under-laid by proper stress barriers. Second, a commercial 3-D fracture simulator (@Frac 3D) was used to study the impact of changing the rheological properties of the injection fluid such as viscosity, solids concentration, and injection rate on the geometry of the hydraulic fracture and net pressure. The results show that solids concentration, injection rate and fluid viscosity are proportional to the fracture width and net pressure.

Abstract: A synthesis of treatment design parameters, treatment procedures in the field, quality control, and analysis of procedures in the field, quality control, and analysis of created fracture parameters is essential to improve and optimize hydraulic fracture treatments in a particular field. This paper provides a step-by-step approach to treatment design optimization that combines laboratory, field and analytical efforts. The laboratory program includes measurements of porosity, absolute and relative permeability, capillary pressure, elastic moduli, matrix permeability, capillary pressure, elastic moduli, matrix permeability and proppant bed sensitivity to fluid (reservoir permeability and proppant bed sensitivity to fluid (reservoir and treatment) all at simulated in-situ conditions and appropriate petrographic study. The field test program involves in-situ stress measurements (mini-fracs in the pay and surrounding formations), fracture orientation pay and surrounding formations), fracture orientation determination and transient pressure tests. Successful implementation of the optimized design is then carried out by monitoring of flow rate and bottom hole pressure during the job and change of design parameters as necessary to tailor the fracture geometry. This must be coordinated with a quality control program for both the equipment and materials used in the job. A brief review of the state-of-the-art of transient pressure analyses of fractured wells is also included in the paper to inform the practicing engineer of the advantages, disadvantages and limitations of each technique. Finally, a field example is presented that illustrates the step-by-step approach. Designed and created fracture parameters are critically compared to demonstrate the effectiveness of the procedure and show how such information can be used to further improve results.

Abstract: Produced water reinjection (PWRI) offers an efficient and effective means of disposing of the PW waste stream and provides an opportunity for a water drive when applied during waterflooding. The required rate of produced water reinjection can be anticipated using the expected pore volume replacement ratio and water-cut estimated from the production forecast. Fracturing is likely to occur during produced water reinjection at voidage replacement rates. The extent (size) of the induced fracture(s) will significantly impact the waste disposal process. It is, therefore, necessary for well injectivity planning and fracture sizing to have an accurate estimate of pore pressure, the rock's mechanical properties and the minimum in-situ stress in the injection horizon. This collective information can be used to estimate the required injection pressure and the number of injectors throughout the production period. In addition, well planning and design will also benefit from predictions concerning the injector performance histories - and the length of the created fracture. Overall, the waterflood planning-cycle efficiency will be increased.

Abstract: Injection and hydraulic fracturing in plastic shales can be a complex and problematic operation. Issues that accompany such treatments include shale swelling, plastic deformation, embedment's and perforation tunnel stability issues. Simulators that model fluid or slurry injection in plastic shale have always overlooked the plasticity issues associated with these formations. The approach has led to erroneous estimation of fracture extent and dimensions. Post injection shale deformation due to pore pressure changes can also lead to detrimental effects on productivity (fracture closure due to creep) and well/casing failure. The current paper offers clear quantitative insights into the overall effect of injection in plastic shales. The experience is gained through drill cutting injection operations that have been taking place in highly plastic shales in an environmentally sensitive remote location. Fracture and slurry containment have been investigated using state-of-the-art 3D fracture simulator to provide assessment of the injection and to estimate out-of zone growth as well as shale plastic deformations and the effects on fracture vertical growth at different batch volumes. Analysis of historical pressure trends and pressure fall-off tests confirmed results from the 3D Simulation and the injection history. The results provide insights that have implications on the job design and implementation of hydraulic fracturing in plastic shale gas, particularly the Haynesville. The results from the 3D fracture simulator and pressure transient analysis combine to accurately assess fracture vertical and lateral extents in similar formations, hence, minimizing the risks associated with injection and fracturing in these highly plastic shales.

Abstract: Optimized hydraulic fracture design requires formation permeability as an input, but it is difficult to quantify in tight gas and shale gas reservoirs. After closure analysis (ACA) following a minifrac or fracture calibration test may offer a means to determine the formation permeability in cases for which both a formation test and a conventional pressure buildup test are impractical and/or unable to provide the permeability. However, ACA techniques use a variety of specialized plots, and there is a risk that apparent straight lines may lead to erroneous results. This paper proposes a technique that provides a simple way to calculate formation permeability, initial reservoir pressure, fracture length, and closure pressure from a single specialized plot. The proposed technique is compared with the G-function method for the estimation of the closure pressure. In addition, it is compared with 3 ACA techniques (Benelkadi, Gu, and GFunction) used in the literature to calculate formation permeability for tight gas and shale gas wells.

Abstract: The widespread use of FracPack technology in deepwater reservoir has been a growing practice. Its purpose is sand control and well stimulation. To-date, field applications and fracture treatments have been designed using traditional hydraulic fracturing simulators that apply LEFM theories. While this is adequate for hard rocks (e.g., tight gas formations), the fracture geometry predictions fall short when applied to fracturing soft rocks. Soft rocks are normally at incipient plasticity and, hence, are prone to compaction. Compaction, or plastic rock deformations during sand control FracPacks operations and disposal of drilling cuttings slurries in soft layers. The capacity of the created fracture to store or accept solids, the conditions of the rock strength near the fracture faces and the near well/fracture rock porosity or permeability are all highly impacted by the rock compaction during the fracture propagation process. The objective of the presented research is to assess the impact of compaction and plasticity on fracture geometry and formation properties around the fracture. In particular, it is important to quantify the details of the geometry of factures generated during FracPack and waste disposal operations as well as the porosity/permeability changes in the vicinity of the fracture faces.

Abstract: The theory describing a pseudo-three-dimensional (pseudo-3D) hydraulic fracturing model that solves the coupled fluid-flow and elastic-rock-deformation problem associated with a fracture propagating into a zone composed of three or more layers is presented. The fracture is initiated in the center layer. Fracture growth is formulated from the critical-stress-intensity-factor criterion, and fracture width is obtained from plane-strain elasticity solutions. Fluid fronts and proppant settling during fracture closure are tracked during the treatment. Fracture parameters obtained by this model show excellent agreement (6% maximum difference) with the solution given by a 3D simulator. Also, designs of hydraulic fracturing treatments depicting ways to minimize fracture growth and to optimize proppant distribution are described. The explicit expressions developed for modeling the fracture growth and fracture opening have reduced the complexity of the formulation and the computational effort.

Abstract: This paper presents a novel technique for assessment of fracture and injection domain geometry from fall off tests. Using type curve analysis techniques established in part for long term water injection, algorithms were developed for assessment of geomechanical and fracture properties of injectors. These properties include the stress contrast between the injection and containment layers, the rate of fracture shrinkage (height and/or length) during fall off, the extent of the inner relative permeability domain and outer domain, and others. A software tool was developed to incorporate these algorithms. The tool was used to analyze fall-off test results obtained from a large-scale slurry injection operation used for disposal of drilling wastes in Alaska’s North Slope. The software tool’s predicted fracture height showed very good agreement to the height interpreted from temperature logs conducted by the operator in the well.

Abstract: A procedure to detect and to evaluate fracturing during waterflooding is described. The approach requires (1) use of a radial-flow analysis to detect changes in fluid transmissibility, (2) determination of the in-situ stress changes, caused by pore pressure buildup and temperature decrease, and comparison of the modified stresses with the bottomhole pressure (BHP), and (3) modeling of the fracture by means of a pressure (BHP), and (3) modeling of the fracture by means of a three-dimensional(3D) hydraulic fracture simulator. This procedure is applied to 30-day waterflooding injection into a limestone oil reservoir located in an offshore well within the Idd el Shargi reservoir (Qatar) in which fracture occurrence was suspected. Both the radial-flow analysis and the quantification of stress changes indicated the occurrence of fracture. Finally, the resulting fracture geometry was delimited by simulation of the fracturing process.

Abstract: Determining fracture height following hydraulic stimulation of a well is an important step in both evaluating the effectiveness of the treatment and estimating the subsequent production behavior of the well. Unfortunately, the temperature and gamma ray logs commonly used to assess fracture heights seldom yield unambiguous results. A new approach to the problem employs spectral gamma ray data to resolve some of these uncertainties. This paper outlines the method and presents data from a paper outlines the method and presents data from a field study made using the new technique.

Abstract: During hydraulic fracturing operations, conventional pressure fall-off analyses (G-Function, Square Root of Time, and Diagnostic Plots) are the main methods for predicting fracture closure pressure. However, there are situations when it is not practical to determine the fracture closure pressure using these analyses. These conditions occur when closure time is long, such as in mini-frac tests in very tight formations, or waste fluid injection in reservoirs where there is low native permeability or where there is significant near wellbore damage. In these situations, it can take several days for the shut-in pressure to stabilize enough for conventional pressure fall-off tests analyses to be used. Thus, the objective of the present study is to attempt to correlate the fracture closure pressure to the early time fall off data using the field-measured Initial Shut-in Pressure (ISIP), rock properties and pumped / injection volumes.

Abstract: Underground injection of slurry in batches or cycles with shut-in periods allows fracture closure and pressure dissipation which in turn prevents pressure accumulation and injection pressure increase from batch to batch. The "G-function" technique is a well-known method for analyzing the pressure fall off data and has been used in monitoring the evolution of formation stress and to identify the fracture closure point after each injection batch. However, in many cases the accumulation of solids on the fracture faces slows down the leak off which can delay the fracture closure up to several days. Well shut-in for such a long time between the batches is impractical. The objective of this work is to develop a new predictive method to monitor the stress increment evolution when well shut-in time between injection batches is not sufficient to allow the fracture to close.

Abstract: Underground injection of slurry in cycles with shut-in periods allows fracture closure and pressure dissipation which in turn prevents pressure accumulation and injection pressure increase from batch to batch. However, in many cases, the accumulation of solids on the fracture faces slows down the leak off which can delay the fracture closure up to several days. The objective in this study is to develop a new predictive method to monitor the stress increment evolution when well shut-in time between injection batches is not sufficient to allow fracture closure. The new technique predicts the fracture closure pressure from the instantaneous shut-in pressure (ISIP) and the injection formation petrophysical/mechanical properties including porosity, permeability, overburden stress, formation pore pressure, Young's modulus, and Poisson's ratio. Actual injection pressure data from a biosolids injector have been used to validate the new predictive technique. During the early well life, the match between the predicted fracture closure pressure values and those obtained from the G-function analysis was excellent, with an absolute error of less than 1%. In later injection batches, the predicted stress increment profile shows a clear trend consistent with the mechanisms of slurry injection and stress shadow analysis. Furthermore, the work shows that the injection operational parameters such as injection flow rate, injected volume per batch, and the volumetric solids concentration have strong impact on the predicted maximum disposal capacity which is reached when the injection zone in situ stress equalizes the upper barrier stress.

Abstract: Slurry waste management may involve injection of solid-laden fluids with concentration up to 25%. To accomplish this without plugging the near wellbore pore space, a fracture is created first using a pad of clean fluid. In some cases, where the formation has a high permeability-thickness product, kh, high injection flow rate is needed to open up the fracture with clean fluids. Most disposal wells do not have large enough pumps to provide the needed flow rates. A combination of a lack of geomechanical understanding combined with poor injection or facility design leads some operators to create high formation damage around their wellbores in slurry injection applications by injecting slurry at flow rates which are insufficient to open fractures. Moreover, the damage causes injection pressure to build up rapidly, facilitating the creation of short fractures which tend to cause near wellbore stresses to increase more rapidly for a given amount of solid deposition than is the case with longer fractures. This paper presents one case study which evaluates the injection well using operational data.

Abstract: A computational method is outlined for modeling the three-dimensional development of hydraulic fractures due to the injection of a non-Newtonian fluid at the well bore. The rock formation is modeled as an infinite, homogeneous, isotropic, elastic solid with in situ stresses that vary with depth. This three- dimensional problem is made two-dimensional by reducing the elasticity problem to an integral equation that relates pressure on the crack faces to crack openings and by pressure on the crack faces to crack openings and by neglecting the component of the fluid velocity in the direction perpendicular to the fracture plane.

Authors: Abou-Sayed, A.S., and Clifton, R.J.

Copyright 1985, Society of Petroleum Engineers

The American Petroleum Institute estimates that about 1.21 bbl of drilling waste are generated for every foot drilled in the U.S., nearly 50% of which is solid waste. Though various federal and local laws and regulations govern the disposal of oilfield waste, regulatory compliance is not itself a sufficiently high standard to ensure the industry’s license to operate. Especially in this period of declined oil prices, with operators driven to cut costs wherever possible, it is critical that as an industry we recognize those technologies that provide a high degree of environmental surety while reducing near-term and long-term costs. We must demonstrate that we can manage our wastes in ways that improve the economic and environmental sustainability of our developments.

Abstract: Many of the world's Mega-fields (> 1 billion barrels of reserves) contain sour gas, a blend of natural gas and hydrogen sulfide (H2S), either alone or in combination with carbon dioxide (CO2). H2S gas is extremely toxic, the combination of H2S and CO2 (Acid Gas - AG), can be highly corrosive, the elemental sulphur reacts with water to form acid rain, and CO2is now recognized as a significant green house gas. Where there is a demand for the natural gas, and capacity to separate the components, the H2S and CO2 can be separated out. However, these components must be managed in a cost-effect way and according to regulatory requirements to maximize recovery of hydrocarbons and minimize AG safety and environmental impacts. To date, the CO2 components have typically been vented to the atmosphere, and sulphur has been produced for industrial uses. Novel step changes are needed to handle the large sour gas volumes to be produced by the mega-fields under development in the Caspian Sea and Middle East regions.

Abstract: Many of the largest fields yet to be developed around the world contain oil, water, and high concentrations of sour gas.The fact that they are still undeveloped reflects the significant political and economic hurdles they have yet to overcome.Successful production of such fields will require careful management of surface resources (land, water, and power), subsurface resources (hydrocarbons), and associated streams (produced water, non-salable products, and E&P wastes).Several fields in the Caspian Sea are awaiting full development because they are burdened by the high expected cost and severe legal and economic risks associated with high hydrogen sulphide (H2S) content. Advantek International was contracted to undertake a comparative analysis of the engineering requirements, environmental impact risks, and economics for disposal of several associated streams in a Caspian field with 20% acid gas (CO2 and H2S). Several technologies are available to the Operator for handling the acid gas after separating from the hydrocarbons, including chemical conversion to "benign" elemental components, underground sequestration (disposal), and underground injection for enhanced oil recovery (EOR). Underground sequestration of some E&P associated streams (produced water, drill cuttings slurries, and completion fluids) have been practiced for many years, as has been injection of natural gas and CO2 for EOR. Sour gas injection, however, is a relatively new technology, with a limited experience base. This paper reviews comparative economic and risk analyses of various acid gas management options available to developing sour fields, considering the impact on recovery (including rate, ultimate total volume, engineering capacity), human health and safety risks, impacts on the environment, reputation consequences, implementation complexity, initial investment (capital and lead time), and potential regulatory restrictions (based on current North American standards, recent judicial actions, and Kyoto Protocols). The greatest opportunity for both improved value and reduced risk lies with reinjecting the acid gas for EOR.While uncertainty regarding the range of value is large, there are no risks that should be considered too severe or unmanageable to undertake this option.

Abstract: This paper presents the results of an extensive study and field test carried out at the site of Prudhoe Bay's four oily waste injection wells. Prudhoe Bay's four oily waste injection wells. The field work was part of an overall environmental assessment intended to: (1) confirm earlier results indicating that no fluid communication was occurring with the permafrost; (2) determine optimum conditions for the disposal of waste in the presence of hydraulically-induced fractures; (3) substantiate that an increased injection pressure could be safely implemented. A three day injection test, including a step-rate stage, was carried out. Data collected included surface and downhole pressures, in-situ stress measurements, and pressures, in-situ stress measurements, and monitoring of ground surface deflections and wellbore hydraulic impedance. Radially symmetric surface tilt patterns showed that the test well connects to a horizontal fracture of 60-foot radius. Wellbore impedance indicated that a horizontal fracture with 9-18 foot radius communicated with the well. Integration of rock mechanics, historical information, and the collected data provided a clear picture of what was occurring underground. The different evaluation techniques showed consistent results as reflected in the estimated fracture size, placement and damage zone properties. properties.

Abstract: During hydraulic-fracturing operations, conventional pressure-falloff analyses (G-function, square root of time, and other diagnostic plots) are the main methods for estimating fracture-closure pressure. However, there are situations when it is not practical to determine the fracture-closure pressure using these analyses. These conditions occur when closure time is long, such as in mini-fracture tests in very tight formations, or in slurry-waste-injection applications where the injected waste forms impermeable filter cake on the fracture faces that delays fracture closure because of slower liquid leakoff into the formation. In these situations, applying the conventional analyses could require several days of well shut-in to collect enough pressure-falloff data during which the fracture closure can be detected. The objective of the present study is to attempt to correlate the fracture-closure pressure to the early-time falloff data using the field-measured instantaneous shut-in pressure (ISIP) and the petrophysical/mechanical properties of the injection formation.

Abstract: The E&P industry is rich in all types of data. Without proper database and analytics, companies are not able to retrieve and analyze the data they need in an efficient way. The result of the data management problems is that decisions are often made using incomplete or incorrect information. Even when the desired data is accessible, requirements for gathering and formatting it may limit the amount of analysis performed before a timely decision must be made. Strong data management is required to transform wells-related data into an integrated system of information. The key to successful data management is in the use of sophisticated platform-independent codes that doesn't need any special setup or systems which allows easy transfer of information and data over the internet. This paper describes the data management and accompanying analytics approach taken in support of operations in Egypt to provide a shared knowledge system. This innovative cloud application provides a common interface to multiple systems in the organization, allowing a richer and more complete source of data to be used for decision making. Moreover, it enables the integration of static data, such as well logs in a particular region, with a real-time system to facilitate integrative real-time analyses using artificial intelligence, cloud-hosted physics-based simulators, or both. To support deepwater needs such as those in Egypt, the system incorporates productivity optimization analysis, reservoir geomechanics (pore pressure prediction, log interpretation, reservoir collapse, fault activation, subsidence, compaction, etc.), and data mining of key development uncertainty and well performance drivers.

Abstract: Development of assets in new frontiers can be quite costly, especially in deep-water and ultra-deep waters. These developments have many uncertainties, and each has an associated risk to both operations and project economics. Leveraging the fact that a significant amount of information has been (and continues to be) gathered in public and/or private domains for many of these assets/wells, a multi-year effort to build a data-mining framework for establishing whether well completion and production performance could have been accurately predicted during various stages of deep-water development ("Pre-Discovery," to "Exploration," through to "Mature Fields") was undertaken. The final results of this work were incorporated into a selection/prediction software tool and database for decision support. The work helps establish priority for data acquisition and data values throughout asset development.

Abstract: Appraisal is a key step in consenting to develop an asset, or abandoning it, and is pursued after successful drilling of an exploration well in a potential field. During the appraisal process the drainage area and original hydrocarbons in place, as well as ultimate recovery (EUR) from the field are estimated which are often based on minimum set of information gathered during the exploration phase. This lack of data, along with uncertainties surrounding the appraisal data, introduces high degrees of variations in pre- and post- sanction EURs (EUR). These estimates, however, are revisited each time new data becomes available and as a result, the EUR from a field, along with several other factors, is subject to change over the field lifespan. Identifying the key drivers in accurate pre-sanction estimation of ultimate recovery and reducing post sanction EUR variance, helps in resource allocation and sustainable field development.

Abstract: Remote life monitoring of field operations, such as injection, has been very restricted although real-time data is often collected at field sites. The difficulties lie in the data access and limitations to obtain computing resources for data analysis, which restricts the engineers' abilities to provide useful and timely remote assessment and assurance to the operations. Cloud computing combined with web-based apps, however, makes it much easier and cheaper to remotely monitor field operations and parameters in real-time from anywhere around world. The current work provides our first attempt to apply the cloud computing and web-powered apps to monitor slurry injection at one injection site in Texas, USA. The site provides real-time injection data including flow rate and surface treating pressure, as it is recorded and stored automatically in a cloud database. The data can then be accessed and analyzed through a web-based app from any web-enabled device. Monitored injection pressure and rate, provide the basis for pressure fall off analysis to evaluate injection formation pressure and stress change, estimate fracture skin, and determine injection-induced fracture geometry at the end of each slurry injection batch. If the fall off analysis yields an unanticipated fracture geometry, advanced fracture simulations would be conducted to model fracture growth in three-dimensions under real injection conditions in order to gain a better understanding of the effects of a specific injection on fracture geometry.

Abstract: Rate of penetration (ROP) is the main function that affects drilling operation economically and efficiently. Many theoretical models reported in the literature were produced to predict ROP based on different parameters. Most of these models used only drilling parameters to estimate ROP. Few models have considered the effects of drilling fluid on ROP using a simulated data or a few real field data. Some of the researchers used artificial intelligence to predict ROP by only one method. The objective of this research is to predict ROP based on both drilling parameters and mud properties such as weight on bit (WOB), rotary speed (RPM), pump flow rate (Q), standpipe pressure (SPP), drilling torque (τ), mud density (MW), plastic viscosity (PV), funnel viscosity (FV), yield point (YP) and solid (%). More than 400 real field data in shale formation are used to predict ROP using support vector machine (SVM) which is a method of artificial intelligence (AI) and compare it with different mathematical models. The result showed that support vector machine (SVM) technique outperformed all the theoretical equations of ROP by a high margin as shown by a very high correlation coefficient (CC) of 0.997 and a very low average absolute percentage error (AAPE) of 2.83%.

Abstract: The recent proliferation of resources exploitation, in both traditional and unconventional basins, has led to more upstream oil and gas industry activities in more regions than ever. These newer activities, when added to the already challenging work environments in such frontiers areas as deep water and the Arctic, place tremendous demands on the industry to work more efficiently and avoid risks to people, capital, and the environment. An emphasis on monitoring and assurance of the production operations during exploitation has caused the oil and gas industry to enter the digital age during these last two decades in a grand way and has generated what the information technology (IT) industry calls “big data.” Data acquisition in instrumented wells and monitoring of fields and operations processes are routinely carried out in both real-time and post-mortem modes. Management and use of this big data have become critical for the industry and its stake holders, including regulators and financiers. Integration of data analytics into the practice of petroleum engineers is essential to establishing a vision for the oil and gas industry to move toward data-based decisions in the production and operations arena.

Abstract: This paper presents a new approach to improving service quality by measuring the effectiveness of training in improving behavioural competency using both qualitative and quantitative techniques. The result is improved waste injection operational service quality to both internal and external clients. A new company high-pressure pumping standard and competence-based training programme (competence: defined by ISO 10015 as the ‘application of knowledge, skills, and behaviours in performance') has been developed by subject matter experts using a collaborative approach incorporating best industry practice and operational lessons learned. Implementation of the standard required the development of competence-based training, given that personnel competency is a key component in the delivery of service quality excellence. The training involves the use of computer-based awareness training, computer-based simulator, and operation of actual workplace equipment. Trainees are assessed when performing task-based operational activities conducted by assessors (skills) in combination with successful completion of examination (knowledge) with training evaluation via subjective trainee feedback. The successful completion of an examination and tasks under controlled training conditions alone cannot measure whether (behavioural) change has been embedded into workplace operations. Quantitative data has been gathered from trainees by examination before and after delivery of training to determine knowledge improvement. Qualitative data has been collated from trainees and workplace supervisors detailing the increase in competence through the improved knowledge, skills and behaviours gained from training and subsequent application in a workplace environment. An analysis of data and the application of this approach demonstrate the value of this process in enabling the Company to focus resources most effectively on service quality.

Abstract: Alaska's Grind and Inject (GNI) operations represent the longest and largest semi-continuous solids waste slurry injection project worldwide. More significant in the current climate of corporate responsibility is that modeling updates and assurance processes allow procedural updates to maintain efficiency and environmental integrity. The modeling program provides data for injection performance analysis and history matching that leads to better understanding of subsurface dynamics. Operational success is evidenced by unblemished capacity to accept large waste volumes with significant ultimate well disposal potential. This paper addresses injection assurance and waste containment throughout project life. The periodic history match of created subsurface features is a major component of this process. Fracture simulation was carried out to match the subsurface response to slurry batch injection through 8 years of injection. The geomechanical modeling necessary to provide the framework on which the simulation works is described. Stress evolution and thermal effects during batch injection is also illustrated for the GNI environments. The disposal domain development has been inferred from the simulation. The provision of designs, solutions and predictions based on the simulation sensitivity studies is described and the impact of field activities is highlighted. Designs, solutions and predictions are given based on the numerical results and sensitivity study verified by past field observations. The verification and updating of the model developed for the GNI operation is provided by the history matching of wellhead pressures through eight years of injection.

Abstract: Alaska's Grind and Inject (GNI) operations represent the longest and largest semi-continuous solids waste slurry injection project worldwide. More significant in the current climate of corporate responsibility is that modeling updates and assurance processes allow procedural updates to maintain efficiency and environmental integrity. The modeling program provides data for injection performance analysis and history matching that leads to better understanding of subsurface dynamics. Operational success is evidenced by unblemished capacity to accept large waste volumes with significant ultimate well disposal potential. This paper addresses injection assurance and waste containment throughout project life. The periodic history match of created subsurface features is a major component of this process. Fracture simulation was carried out to match the subsurface response to slurry batch injection through 8 years of injection. The geomechanical modeling necessary to provide the framework on which the simulation works is described. Stress evolution and thermal effects during batch injection is also illustrated for the GNI environments. The disposal domain development has been inferred from the simulation. The provision of designs, solutions and predictions based on the simulation sensitivity studies is described and the impact of field activities is highlighted. Designs, solutions and predictions are given based on the numerical results and sensitivity study verified by past field observations. The verification and updating of the model developed for the GNI operation is provided by the history matching of wellhead pressures through eight years of injection.

Abstract: Remote live monitoring of field operations, such as injection, has been very restricted, although real-time data are often collected at field sites. The difficulties lie in the data access and limitations to obtain computing resources for data analysis, which restricts the engineers’ abilities to provide useful and timely remote assessment and assurance to the operations. Cloud computing combined with web-based apps, however, makes it much easier and cheaper to monitor field operations in real time from anywhere around world. The current work provides our first attempt to apply the cloud computing and web-powered apps to monitor slurry injection at one injection site in Texas, USA. The site provides injection data that is stored automatically in a cloud database. The data are accessed and analyzed remotely through a web-based app in real time. Monitored injection pressure and rate provide the basis for pressure fall off analysis. If the fall off analysis yields an unanticipated fracture geometry, advanced 3D fracture simulations would be conducted to gain a better understanding of the effects of a specific injection on fracture geometry. The results of remote real-time data analysis set up early warnings to alert both onsite and offsite staff ahead of operational upsets. Compared to traditional desktop applications and isolated local data servers, cloud computing and web-based apps provide a more convenient and cost-effective way to monitor field operations in real time. The technique and workflow presented here may also be applicable to monitor other field operations.

Abstract: In a slurry injection application, the goal is to inject high solid content fluids (up to 25%). To accomplish this without plugging the near-wellbore pore space, the fracture is created using a pad of clean fluid. Once the fracture is open, the slurry is introduced to the formation. In some cases, where the formation has a high permeability-thickness product (k × H), a high injection flow rate is needed to open up the fracture with clean fluids. Most disposal wells do not have large enough pumps to provide high enough flow rates in these circumstances. A combination of a lack of geomechanical understanding combined with poor injection or facility design leads some operators to create high formation damage around the wellbores in slurry injection applications by injecting slurry at flow rates which are insufficient to open fractures. When solids-laden fluid slurries are injected under a matrix flow regime, suspended solids will plug the near-wellbore pore throats and will form a filter cake layer at the formation face, causing the injection pressure to gradually increase. At the point where the injection pressure exceeds the formation fracture pressure, the formation will finally fracture. However, the near-wellbore filter cake remains a factor in future injection and leakoff characteristics. Moreover, the damage causes injection pressure to build up rapidly, facilitating the creation of short fractures which tend to cause near-wellbore stresses to increase more rapidly for a given amount of solid deposition than is the case with longer fractures. Case studies have been presented in this paper which evaluates such slurry injection wells. Based on the data analyzed in this study, inducing the fracture with solids-laden slurry rather than with clean fluid by causes the injection pressure to continuously increase, ultimately leading to significantly reduced formation capacity. Recommendations are presented as well for how to avoid this condition even if the pumps do not have the capacity to provide the required injection flow rate using clean fluid. One such solution is to add a viscosifier to the clean pad fluid to raise the fluid viscosity which enables the creation of a hydraulic fracture at lower flow rate.

Abstract: In April 1998, a program for continuous deep disposal of drill cuttings and open pit materials was initiated on the North Slope of Alaska. This ongoing injection project is commonly referred to as GNI, standing for Grind and Inject. Accumulated drilling cuttings and mud slurry is injected into a receptive cretaceous soft sandstone in three wells, GNI-1, GNI-2, and GNI-3. Typical operations involve injecting slurry into one of the three wells continuously for a number of days and then switching injection to another well. The average injection rate is approximately 30,000 barrels per day. As of September 30, 2002, project injection has included 12.7×106 barrels of water, 30.9×106 barrels of slurry containing 2.0×106 tons or 2.2×106 cubic yards of excavated frozen reserve pit material and drilling solids and 1.31×106 barrels of fluid from ongoing drilling operations. Knowledge of the fate of the drilling and open pit materials during injection is paramount to assure the safe sequestration of the materials without harm to the environment. Numerical modeling, well testing (including step rate and pressure falloff testing) as well as logging surveys were performed periodically to assess the disposal wells' operational integrity and to ensure the safe containment of the disposed waste slurry. The great capacity of these injectors highlighted the mechanisms for slurry being accepted by multiple and branched fractures - part of the slurry went to previous fractures during subsequent batch injections. The current paper will emphasize on how to integrate numerical simulations, well testing/monitoring and operational data to estimate storage capacity and to construct a clear representation of what was happening underground during this grind and injection operation. The work has implications on other large drilling waste injection projects worldwide.

Abstract: Slurry injection is commonly used to dispose of oilfield wastes during the drilling and production phases of a well. Waste types include drill cuttings, drilling fluids, produced sands, and other types of wastes produced during production. Although slurry injection is most effective when hydraulic fractures are created, safe operations demand that the fractures remain contained below one or more confining layers that are situated above the permitted injection zone. This paper outlines how numerical simulations of 3D fracture propagation can be used to accurately forecast and monitor fracture containment in support of ongoing injection operations. In particular, simulation results are used to determine the accumulation of stress caused by ongoing deposition of solids within the fractures and near the wellbore. Five case studies highlight both the numerical methods and best practices for safely operating slurry injection wells. Field observations of pressure-fall off data and extrapolated near-well stress and fracture lengths are found to match closely with numerical results. Recent advances using cloud-based diagnostics of well performance also enable using real-time slurry rheology, injection rate and pressure data to drive numerical fracture simulations to predict how operational decisions impact fracture geometry and subsurface reservoir properties.

Abstract: Assurance of a successful and environmentally sound long-term cuttings injection program requires monitoring and periodic analysis of injection performance response. Such a program provides for operational oversight and the ability to identify changes in performance response or trends, thereby providing for modification of operating parameters to optimize performance and minimize the negative impact of unexpected responses. An implementation of this process has been instituted for a remote, pad-drilled site located in a nature preserve in the Amazonian rainforest of Peru. The development of natural gas reserves at Camisea has extreme environmental sensitivity and injection of the generated drill cuttings was recognized as a technically and environmentally acceptable alternative for drilling location waste management. The paper will discuss the issues encountered in implementing and operating the DCI project at Cashiriari. Higher than anticipated initial injection pressures were indicative of the stress regime of the region and required an adjustment in thinking with respect to operating parameters and performance expectations. Performance has been contingent on successful inhibition of the reactive clays adjacent to the relatively thin sandy target zones. Continuous monitoring has allowed projections of the closure pressure increases associated with batch injection through time, providing a prediction of future performance and disposal capacity. Information gathered from monitoring operations has allowed for performance improvement and/or minimization of potential problems identified. At this point in time, the operation has successfully injected nearly 200,000 bbls of cuttings through careful management of batch attributes and adaptation to operating realities. Recognition of the need for well designed and implemented programs to monitor injection performance is critical for the industry in the future. Operational and environmental assurance derived from such programs provides long term operational viability and social acceptance of cuttings injection as a safe means of waste management.

Abstract: Reactions of CO2 with formation rock may lead to an enhancement in the permeability due to rock dissolution, or damage (reduction in the core permeability) because of the precipitation of reaction products. The reaction is affected by aquifer conditions (pressure, temperature, initial porosity, and permeability), and the injection scheme (injection flow rate, CO2:brine volumetric ratio, and the injection time). The effects of temperature, injection flow rate, and injection scheme on the permeability alteration due to CO2 injection into heterogeneous dolomite rock is addressed experimentally in this paper. Twenty coreflood tests were conducted using Silurian dolomite cores. Thirty pore volumes of CO2 and brine were injected in water alternating gas (WAG) scheme under supercritical conditions at temperatures ranging from 21 to 121 °C, and injection rates of 2.0–5.0 cm3/min. Concentrations of Ca++, Mg++, and Na+ were measured in the core effluent samples. Permeability alteration was evaluated by measuring the permeability of the cores before and after the experiment. Two sources of damage in permeability were noted in this study: (1) due to precipitation of calcium carbonate, and (2) due to migration of clay minerals present in the core. Temperature and injection scheme don't have a clear impact on the core permeability. A good correlation between the initial and final core permeability was noted, and the ratio of final permeability to the initial permeability is lower for low permeability cores.

Abstract: Carbon dioxide (CO2) injection in carbonate formations causes a reduction in the well injectivity caused by precipitation of the reaction products between CO2, rock, and brine. The precipitated material includes sulfate and carbonate scales. The homogeneity of the carbonate rock, in terms of mineralogy and rock structure, is an important factor that affects the behavior of permeability changes during CO2 injection. Limestone rocks that were tested in this study included homogeneous Pink Desert limestone and Austin chalk, which were mainly calcite; heterogeneous Silurian dolomite (composed of 98 wt% carbonate minerals and 2 wt% silicate minerals); and heterogeneous Indiana limestone, which was mainly calcite and had vugs. Experiments were conducted to compare the permeability loss between these rocks during corefloods. CO2 was injected with the water-alternating-gas (WAG) technique. Different brines were examined, including sulfate-bearing seawater and no-sulfate seawater. The experiments were run at a backpressure of 1,300 psi, a temperature of 200°F, and an injection rate of 5 cm3/min. A compositional-simulator tool (CMG-GEM) was used to predict the Carman-Kozeny and power-law exponents on the basis of the experimental results. More damage was observed for heterogeneous rocks compared with the homogeneous cores--the source of damage to permeability for high-permeability cores is the precipitation of reaction products--but for low-permeability cores, capillary forces between CO2 and brine increase the severity of formation damage. The form of the precipitated material changes depending on the core mineralogy and permeability. The simulation study showed that for the cores tested in this study, power-law exponent and Carman-Kozeny exponent between 5 and 6 can be used for the homogeneous carbonate rock to estimate the change in permeability depending on change in porosity, whereas a larger exponent is needed for heterogeneous cores.

Abstract: The damaging effect of calcium sulfate precipitation on the permeability of carbonate cores when mixing hydrochloric acid with seawater for matrix acid treatments has been identified in our recent work (SPE 143855). The objective of this work is to mitigate calcium sulfate precipitation by using a suitable scale inhibitor in hydrochloric acid. Another objective is to determine the scale inhibitor type, concentration, and whether it is needed in the preflush or post-flush stages. Core flood tests were conducted using Austin Chalk cores (1.5 in. × 6 in.) with a permeability of 5 md, to investigate the effectiveness of scale inhibitor. A synthetic seawater was prepared according to the composition of seawater in the Arabian Gulf. Calcium, sulfate ions, and scale inhibitor concentrations were analyzed in the core effluent samples. The minimum concentration of scale inhibitor was determined over a wide range of temperatures (77 to 210°F). A scale inhibitor (sulfonated terpolymer) was found to be compatible with hydrochloric acid systems, and can tolerate high concentrations of calcium (30,000 mg/l). Analysis of the core effluent indicated that the new treatment successfully eliminated calcium sulfate scale deposition. The concentration of scale inhibitor ranged from 20 to 250 ppm, depending on the scaling tendencies of calcium sulfate. This work confirms that an appropriate scale inhibitor can be added to acid, to avoid calcium sulfate precipitation when seawater is used to prepare hydrochloric acid for matrix acidizing.

Abstract: CO2 injection in carbonate formations causes a reduction in the well injectivity, due to precipitation of the reaction products between CO2/ rock/brine. The precipitated material includes sulfate and carbonate scales. The homogeneity of the carbonate rock, in terms of mineralogy and rock structure, is an important factor that affects the behavior of permeability changes during CO2 injection. Limestone rocks represent the homogenous rock in this study, and include: Pink Desert limestone and Austin chalk, which are mainly calcite. Silurian dolomite (composed of 98% carbonate minerals, and 2% silicate minerals) and Indiana limestone rock represent the heterogeneous rock, which have some vugs in their structure. Coreflood experiments were conducted to compare the behavior of the permeability loss between these rocks. CO2 was injected with the water alternating gas (WAG) technique. Different brines were examined including seawater and no sulfate seawater. The experiments were run at a pressure of 1300 psi, a temperature of 200°F, and an injection rate of 5 cm3/min. A compositional simulator tool (CMG-GEM) was used to confirm the experimental results obtained in this study. The results showed that for homogenous rocks, the presence of sodium sulfate in the injected seawater is the major factor that causes formation damage, due to calcium sulfate precipitation in CO2 environments. For dolomite rocks, higher damage was noted, due to the reactions of CO2 with the silicate minerals. For both homogenous and heterogeneous rocks, the source of damage for high permeability cores is the precipitation of reaction products, while for low permeability cores, water blockage increases the severity of formation damage. The simulation study showed that the power-law exponent, and Carman-Kozeny exponent between 5 and 6, can be used for homogenous carbonate rock to estimate the change in permeability based on the change in porosity, for heterogeneous rock a larger exponent was needed.

Abstract: In offshore operations where seawater is commonly used to prepare hydrochloric acid, calcium sulfate precipitation, the potential of which can greatly reduce the effectiveness of these treatments. This is because high concentration of calcium produced in spent acid mixed with high level of sulfate in seawater. However, a few studies have provided evidence for this problem and the effect of calcium sulfate precipitation on acid treatments has not been fully examined. In this work, core flood experiments at 0.5, 1, and 5 cm3/min flow rates were performed at 25°C to investigate formation damage due to calcium sulfate precipitation during matrix acidizing treatment. Austin Chalk cores (6 in. length and 1.5 in. diameter) with a permeability of 10 md and synthetic seawater were used. The core permeability before and after acid treatment, pressure drop response, calcium ion, sulfate ion, and pH values in the core effluent samples were measured. Solids collected in the core effluent samples were analyzed using XPS technique. Both acid prepared in seawater and in deionized water were examined. Results showed that calcium sulfate precipitation occurred when seawater was used in any stage during matrix acidizing including preflush, post-flush, or in the main stage. Injection rate was the most important parameter that affected calcium sulfate precipitation; permeability reduction was significant at low flow rates, while at high rates wormhole breakthrough reduced the severity of the problem. This work confirms the damaging effect of preparing hydrochloric acid using seawater for acid treatments.

Abstract: Carbon capture and storage (CCS) has been proposed to mitigate the accumulation of CO2 in the atmosphere. Water alternating gas (WAG) technique is used in the industry to inject CO2 into underground formations either in sequestration or in EOR. CO2 dissolves in water, generating carbonic acid, which dissolves carbonate rock. The composition of the water is a critical factor that affects the rock permeability during sequestration. Sulfate content of the injected water can cause precipitation of calcium sulfate, which can negatively affect the rock permeability. This paper addresses potential formation damage due to sulfate precipitation during CO2 sequestration. A core flood study was conducted using limestone cores. CO2 was injected at pressure greater than 1300 psi and temperatures (70 and 200°F). CO2 and brines were injected in WAG cycles under injection rates of 2 and 5 cm3/min. Seawater and formation brine were examined in this study. Core effluent samples were collected and concentrations of calcium and sulfate ions were measured to assess calcium sulfate precipitation. Core permeability was measured before and after the experiment. The results show that temperature is the main parameter that affects sulfate precipitation during CO2 sequestration. Injection rate doesn't have a significant effect on the core permeability. At high salinity calcium sulfate precipitation occurs even with low sulfate concentration present.

Abstract: Carbon dioxide sequestration in deep saline aquifers is being considered as one of the more important geological sequestration types due to the potentially large storage capacity when compared to some other geological sequestration reservoirs. CO2 will react with formation rock when injected in dolomite formations, due to the rock dissolution and precipitation of reaction products permeability may be changed. Several parameters affect these interactions including pressure, temperature, brine composition, CO2 injection rate, and overall injection scheme. This paper addresses the effect of the temperature, injection rate, brine composition, and injection scheme on the damage generated in the formation due to CO2 injection. A core flood study was conducted using dolomite cores. CO2 was injected under supercritical conditions at a pressure of 1,300 psi, and at temperatures ranging from 70 to 200°F, and injection rates of 2.0, 3.5 and 5.0 cm3/min. Core effluent samples were collected and the concentrations of calcium and magnesium ions were measured. Core permeabilities were measured before and after the experiment to evaluate the damage generated. The results show that temperature, injection flow rate, and injection scheme don't have a clear impact on the core permeability, the main factor that affect the change in core permeability is the initial core permeability. The damage is mainly due to calcium carbonate precipitation, and the precipitation of the reaction products between silicate minerals that present naturally with dolomite and CO2.

Abstract: Carbonate reservoir stimulation has been carried out for years using HCl-based fluids. High HCl concentrations should not be used when the well completion has Cr-based alloy in which the protective layer is chrome oxide, which is soluble in HCl. HCl or its based fluids are not recommended either in shallow reservoirs where the fracture pressure is low (face dissolution) or in deep reservoirs where it will cause severe corrosion problems. Different chelating agents have been proposed to be used as alternatives to HCl in the cases that HCl cannot be used. Chelating agents such as HEDTA (hydroxyethylenediaminetriaceticacid), and GLDA (L-glutamic acid -N,N-diacetic acid) have been used to stimulate carbonate cores. The benefits of chelating agents over HCl are the low reaction and corrosion rates. In this study, the effect of core length on the volume required to create wormhole was investigated using Indiana limestone cores of an average permeability 3 md and core lengths from 1 to 20 in. Chelating agents were tested at pH value of 4 and a concentration of 0.6M and their performance was compared with that of 15 wt% HCl. Experimental results showed that the volume of HCl required to create wormholes increased when core length was 20 in. This effect was different from that noted when chelating agent were used. Increasing the core length for chelating agents decreased the volume required to create wormholes in the carbonate cores at the same conditions. This is because of the increased contact time by increasing the core length. Chelating agents can be used to stimulate shallow reservoirs where HCl causes face dissolution. They can be used in deep reservoirs where HCl can cause severe corrosion to well tubulars.

Abstract: Chemical interactions between CO2/brine/rock can cause formation damage during CO2 injection. These interactions can affect injectivity during EOR operations, as well as affect storage capacity and seal integrity, which are primary concerns during CO2 sequestration. These interactions and the degree of impact are affected by several parameters, including pressure, temperature, brine salinity, CO2 injection rate, and rock characteristics. Carbonic acid generated from dissolution of CO2 in the formation brine can dissolve carbonate rock. Concurrently, calcium concentration increases in the brine may cause calcium carbonate to reprecipitate. This paper addresses the effects of the formation temperature, and CO2 injection rate on the precipitation and the relative impact of dissolution and precipitation on well performance. A core flood study was conducted using carbonate rock under various temperatures and injection rates. Core effluent samples were collected and the concentration of calcium was measured as the primary indicator of reactivity. Results showed that CO2 injection increased core permeability at high temperature and injection rate. And the permeability of the inlet part of the core always increases, while the permeability of the rest of the core always decreases.