Creating injection slurries for disposal of oil and gas field waste is standard practice for managing solid waste in environmentally sensitive regions:
- Remote areas
Otherwise, waste would be left in reserve pits, land-farmed, or discharged into the ocean, damaging the environment and threatening the health of the human population.
Slurry injection relies on hydraulic fracturing science to create subsurface voids for storing solids.
Key Concerns about Injection
- Containment of injection waste
- Prevention of humanly perceived seismic activity
Appropriate design standards and constant monitoring of controlling parameters will mitigate much of the concern.
Safe operations are always the highest priority for well operators.
Both surface and subsurface risks must constantly be evaluated using real-time well surveillance to ensure the surface pressures and subsurface behaviors are within bounds. Problems can be managed when you base your planning and operations on understanding subsurface behavior.
Best Practice: Proper Site Research, Construction, and Operation
Determine workflow based on:
- Well logs
- Offset well performance
- Fracture simulation and optimization
Perform proper zonal selection and well construction and remodel the initial parameters once the well is drilled.
Build safe margins into your operating procedures using:
- Log analysis
- Break down and fall-off tests
- Fracture and flow simulations
Best Practice: Manage Injection Fluids to Prevent Formation Damage
Matrix injection is prone to plugging – you need to monitor for fractured injection sites.
Typical Causes of Near-well Damage:
- Oilfield bacteria
- Calcium carbonate
- Iron compounds
- NORM – naturally occurring radioactive materials such as Ra-226 and Ra-228
Monitor your formation after drilling at all times.
Best Practice: Use Injection Diagnostics to Predict Failure Before It Happens
Safe operations require real-time monitoring – continually monitor both the surface pressure and subsurface fracture behavior to assure containment.
- Matrix Injection (injection of water into the disposal zone’s rock matrix)
- Water Injection
- Slurry Injection
Diagnostic tests forecast injection performance trends that indicate potential types of damage and when work-overs may be required.
Best Practice: Minimize All Magnitudes of Seismic Activity
There is a complex web of potential causes, two of which are injection near crystalline basements and the use of high rate injection.
Nearly all cases of suspected injection-induced seismic activity perceived by humans have involved communication between disposal zones and basement faults.
Operators must avoid activation of faulted basement rock:
- Injection in strata near crystalline basements
- Injection zones proximal to faults penetrating into basement
Studies show high injection rates (>300,000 bbl per month) are much more likely to be associated with induced seismic events and includes propagation into faults or other wells.
Advantek Waste Management Services has helped clients inject 1.5 billion barrels of oilfield and other hazardous waste for more than 50 of the biggest national and international oil companies.
Hydraulic Fracturing Library
Technical papers related to hydraulic fracturing, including case studies, advances in model building, and other topics.
"Effect of Injection Fluid Properties on the Hydraulic Fracture Geometry: A Case Study from Texas", "Y Panchal, SM Kholy, M Loloi, IM Mohamed, O Abou-Sayed
Recent Advances in Petrochemical Science (RAPSCI) 3 (5), 4"Click here to view Article
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.
"A Step by Step Approach to Hydraulic Fracture Treatment Design, Implementation, and Analysis for Tight Gas Sands", Ahmed, U., Schatz, J. F., Abou-Sayed, A. S., & Jones, A. H. (1982, January 1). A Step by Step Approach to Hydraulic Fracture Treatment Design, Implementation, and Analysis for Tight Gas Sands. Society of Petroleum Engineers. doi:10.2118/10829-MSClick here to view Article
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.
"Fracture Propagation and Injector Performance Predictive Model During Produced (Dirty) Water Injection", Zaki, K. S., Sarfare, M. D., Abou-Sayed, A. S., & Murray, L. R. (2006, January 1). Fracture Propagation and Injector Performance Predictive Model During Produced (Dirty) Water Injection. Society of Petroleum Engineers. doi:10.2118/98351-MSClick here to view Article
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.
"3D Hydraulic Fracture Simulation for Injection in Plastic Shales", El-Fayoumi, A. M., Zaki, K. S., & Abou-Sayed, A. S. (2011, January 1). 3D Hydraulic Fracture Simulation for Injection in Plastic Shales. Society of Petroleum Engineers. doi:10.2118/142263-MSClick here to view Article
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.
"Evaluation of After-Closure Analysis Techniques for Tight and Shale Gas Formations", Mohamed, I. M., Azmy, R. M., Sayed, M. A. I., Marongiu-Porcu, M., & Economides, C. (2011, January 1). Evaluation of After-Closure Analysis Techniques for Tight and Shale Gas Formations. Society of Petroleum Engineers. doi:10.2118/140136-MSClick here to view Article
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.
"Fracture Propagation and Formation Disturbance during Injection and Frac-Pack Operations in Soft Compacting Rocks", Abou-Sayed, A., Zaki, K., Wang, G., Meng, F., & Sarfare, M. (2004, January 1). Fracture Propagation and Formation Disturbance during Injection and Frac-Pack Operations in Soft Compacting Rocks. Society of Petroleum Engineers. doi:10.2118/90656-MSClick here to view Article
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.
"Microcomputer Analysis of Hydraulic Fracture Behavior With a Pseudo-Three-Dimensional Simulator", Morales, R. H., & Abou-Sayed, A. S. (1989, February 1). Microcomputer Analysis of Hydraulic Fracture Behavior With a Pseudo-Three-Dimensional Simulator. Society of Petroleum Engineers. doi:10.2118/15305-PAClick here to view Article
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.
"A Novel Technique for Assessment of Fracture Geometry and Injection Domain From Falloff Tests After Fractured Injection of Slurry: Case Study", Loloi, M., Abou-Sayed, A., Abou-Sayed, O., & Bill, M. (2014, August 18). A Novel Technique for Assessment of Fracture Geometry and Injection Domain From Falloff Tests After Fractured Injection of Slurry: Case Study. American Rock Mechanics AssociationClick here to view Article
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.
"Detection of a Formation Fracture in a Waterflooding Experiment", Morales, R. H., Abou-Sayed, A. S., Jones, A. H., & Al-Saffar, A. (1986, October 1). Detection of a Formation Fracture in a Waterflooding Experiment. Society of Petroleum Engineers. doi:10.2118/13747-PAClick here to view Article
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.
"Determination of Fracture Height by Spectral Gamma Log Analysis", Anderson, J. A., Pearson, C. M., Abou-Sayed, A. S., & Meyers, G. D. (1986, January 1). Determination of Fracture Height by Spectral Gamma Log Analysis. Society of Petroleum Engineers. doi:10.2118/15439-MSClick here to view Article
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.
"Development of an Empirical Equation to Predict Hydraulic Fracture Closure Pressure from the Initial Shut-in Pressure after Treatment", Kholy, S. M., Mohamed, I. M., Loloi, M., Abou-Sayed, O., & Abou-Sayed, A. (2017, September 13). Development of an Empirical Equation to Predict Hydraulic Fracture Closure Pressure from the Initial Shut-in Pressure after Treatment. Society of Petroleum Engineers. doi:10.2118/187495-MSClick here to view Article
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.
"A New Technique to Predict In-Situ Stress Increment due to Slurry Injection into Sandstone Formations: Case Study from a Biosolids Injector in Los Angeles, California, USA", Kholy, S. M., Almetwally, A. G., Mohamed, I. M., Loloi, M., Abou-Sayed, A., & Abou-Sayed, O. (2018, April 22). A New Technique to Predict In-Situ Stress Increment due to Slurry Injection into Sandstone Formations: Case Study from a Biosolids Injector in Los Angeles, California, USA. Society of Petroleum Engineers. doi:10.2118/190151-MSClick here to view Article
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.
"A New Technique to Predict In Situ Stress Increment Due to Biowaste Slurry Injection Into a Sandstone Formation", Kholy SM, Almetwally AG, Mohamed IM, Loloi M, Abou-Sayed A, Abou-Sayed O. A New Technique to Predict In Situ Stress Increment Due to Biowaste Slurry Injection Into a Sandstone Formation. ASME. J. Energy Resour. Technol. 2018;140(12):122905-122905-9. doi:10.1115/1.4041542.Click here to view Article
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.
"Formation Damage Induced Hydraulic Fracture During Slurry Injection Into High Permeability Sandstone. Is It a Good Practice?", Mohamed, I. M., Algarhy, A., Abou-Sayed, O., Abou-Sayed, A. S., & Elkatatny, S. M. (2018, August 21). Formation Damage Induced Hydraulic Fracture During Slurry Injection Into High Permeability Sandstone. Is It a Good Practice? American Rock Mechanics Association.Click here to view Article
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.
"A Variational Approach to the Prediction of the Three- Dimensional Geometry of Hydraulic Fractures," paper SPE/DOE 9879 presented at the SPE/ DOE Low-Permeability Symposium, Denver, Colorado, May 27-29, 1985.Click here to view Article
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