Abou-Sayed, A.S.
Paper presented at Journal of Petroleum Technology, October 2012, PP 88-95

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.The largest amount of computing power in the industry so far has been dedicated to the collection and storage of information (databases and warehousing) as a result of the low cost and portability both of electronic sensors and computer memory. Great emphasis has been put on automated reporting, standardized presentations, and streamlined data transfer to cut costs for data processing and dissemination. Even when no immediate need for the data was present, the low cost of data collection has driven company decision makers to support data storing and sorting for later analysis. Current databases contain transactions that can be stored and retrieved without relying on employees’ memories. Unfortunately, while information banks are full, clients are not communicating efficiently and data sharing sometimes is inhibited by the size of the specialized warehouses. Integration of the data and coincidence of the information seen by all team members across the organization has been lacking. The more serious gap in this digital age has been in the transformation of this data into information and knowledge that could drive management actions or become the basis for corporate-level decisions.

Paper presented at 10th SPE International Conference and Exhibition on European Formation Damage, 5-7 June, 2013, Noordwijk, The Netherlands.

Abstract

The growing demand for well-designed weighting agents to overcome the currently drilling challenges such as ECD management and the settling tendency of the weighting agents led to the development of a new micronized ilmenite (FeTiO3). The acid solubility of ilmenite is of great importance to remediate any damage that might occur during its use in the drilling operation. Extensive lab work was conducted to: 1) assess the reaction of 10 wt% HCl with ilmenite particles at 300°F and 300 psi using an aging cell, 2) optimize the concentration of HCl to remove the filter cake using a modified HPHT filter press at 250°F, 3) determine the removal efficiency of the filter cake, and 4) calculate the retained permeability of Indiana limestone cores. The reaction of hydrochloric acid with ilmenite showed that HCl (10 wt%) dissolved 75 wt% of the iron from ilmenite particles after 10 hrs of reaction at 300°F. SEM and XRD results showed that the reaction product was mainly rutile (TiO2) after 6 hrs of reaction. Ilmenite-based filter cake was removed completely after reaction with 5 wt% HCl (300 g solution) for 16 hrs soaking time at 250°F. The retained permeability of the Indiana limestone and Berea sandstone cores was nearly 100% after HCl treatment (5 wt%). Removal of ilmenite water-based filter cake is a simple process as compared with barite water-based filter cake, which cannot be removed using HCl. This study will provide a complete evaluation of the reaction of HCl with ilmenite and will help the drilling and completion engineers to better design the chemical treatments to remove the filter cake for HPHT wells.

I.M.. M. Mohamed; H.A.. A. Nasr-El-Din
Presented at SPE J. 18 (03): 468–485.

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.

Paper presented at International Petroleum Technology Conference, Beijing, China, March 2013.

Abstract

Barite is the most common weighting material for drilling fluids, which contain several heavy components including lead, cadmium, mercury, and arsenic. Some of these heavy materials can discharge into the sea, which is not allowed especially in the case of oil-based drilling fluid. The supply of barite is geographically limited, with high transportation costs. To overcome the high cost, shortage, and common problems of barite, an alternative weighting material, ilmenite (5 µm), is introduced which is heavier than barite and more stable at high temperature. Also, the micronized ilmenite was introduced to overcome the ECD challenges in some drilling operations at reasonable cost. Extensive lab work was done in order to: optimize the rheological properties of the drilling fluid; determine the optimum pH that gives stable dispersion; assess the thermal stability,; optimize the filtration parameters (filtrate volume and filter cake thickness), and; characterize the ilmenite-based filter cake. Zeta potential results showed that ilmenite was stable when mixed with water at a pH above 7 and it was dispersed and stable when mixed with the drilling fluid components. Drilling fluids have a density range from 100 to 120 pcf and a plastic viscosity of 28–32 cp. The optimized water-based drilling fluid formula had a small filtrate volume (12 cm3) and thin filter cake (0.2 in.) under dynamic conditions. SEM analysis showed that ilmenite filter cake was heterogeneous and contained ilmenite particles in the layer closer to the rock surface. The kem-seal plus had a big effect to control the rheological properties of the drilling fluid at 350°F. This study will provide a complete evaluation of the drilling fluids with ilmenite as a weighting material and will help drilling engineers to better design drilling fluids for HPHT wells.

Paper presented at SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, March 2013.

Abstract

Cleanup of filter cake generated by high density drilling fluids (1.5 SG) that are based on manganese tetraoxide (Mn3O4) particles as a weigthing material was investigated using a mixture of HCl and glycolic acids. Manganese tetraoxide (Mn3O4) has a specific gravity of 4.8, which means that it can be used to drill deep wells. Because of the hetrogenouty of the filter cake, it was suggested in the literature to degrade the top layer of the filter using an enzyme and dissolve the remaining filter cake using organic acid. HCl at concentrations greater than 5 wt% HCl releases chlorine gas, a toxic and corrosive gas. A Breaker fluid was developed, which combined low and safe concentration of HCl and glycolic acid. Solubility tests conducted at 250°F indicated that glycolic acid alone did not dissolve the filter cake. However, a combination of 7 wt% glycolic acid and 1 wt% HCl dissolved 90% of the filter cake. The acid mixture was tested in a modified HPHT filter press. Indiana limestone and Berea sandstone cores were used at 250°F. The cleaning fluid was very effective in removing filter cake, removal efficiency was nearly 90% and the return permeability was 100%. The filtrate into limestone and Berea cores did not cause any damage.

Paper presented at Faculty of the Graduate School of the MISSOURI UNIVERSITY OF SCIENCE AND TECHNOLOGY

Abstract

Since 2010 the US Environmental Protection Agency (EPA) has been proposing plans to study, and has now initiated research regarding the potential impact of hydraulic fracturing processes on drinking water sources. Their work refers to an ‘Area of Evaluation’ around a hydraulically fractured well, inferring that the wells immediately around hydraulic fractured wells should be studied, to evaluate the conditions of these wells and their potential to contaminate overlying USDWs. Class II injection wells must have a minimum 1/4 mile radius area of review to determine the condition of wells surrounding the proposed injection well. All wells within this AOR are evaluated, although wells that intersect the zone of injection are of greatest interest. This study examines publically available micro seismic data for multi-stage hydraulic fractured horizontal wells in various shale plays. A 1/4 mile AOE is inscribed on each stage the microseismic to determine if all microseismic events fall within this criteria. The study also investigates current state practices with respect to AOE. Results of this study indicate that most wells have hydraulically fractures that fit within current 1/4 mile AOR criteria. While this may not be the only aspect to consider with respect to these types of wells, it is a good starting point for additional study

Mohamed, I.M., He, J., and Nasr-El-Din, H.A.
Presented at Journal of Petroleum Science Research 2(1)14-26, 2013.

Abstract

Several parameters affect the chemical reactions between CO_2/fluid/rock: pressure, temperature, rock type, and brine composition. Brine composition includes salt concentration and type. Pink Desert limestone cores were used to conduct a series of coreflood experiments to address the effect of brine composition on the chemical reactions between carbonic acid and limestone rock. The experiments were designed to simulate the water alternating gas (WAG) injection of CO_2 into saline carbonate aquifers. Supercritical CO_2 and brines were injected at flow rates of 2 and 5 cm3/min at 70 and 200°F. Seawater, formation brine, calcium chloride, sodium chloride, and magnesium chloride brines were used in this study. A commercial compositional simulator was used to simulate the coreflood experiments at the lab conditions. The reaction rate constant of CO_2 with calcite at different brine compositions was adjusted to match the calcium concentration obtained in the lab. Experimental data was used to predict the reaction rate constant between CO_2/brine/rock and found to be increasing as the brine salinity increased (Log(k_(25))= ‐9.2) when CO_2 dissolves in DI water, and ‐6.2 when CO_2 dissolves in 5 wt% CaCl_2 brine). A simulation study conducted on field scale showed that after 30 years of CO_2 injection and 1400 years after injection stopped, brine composition does not affect the trapping mechanism of CO_2 in the aquifer.

Paper presented at SPE Kuwait International Petroleum Conference and Exhibition, Kuwait City, Kuwait, December 2012.

Abstract

Barite is the most common weighting material for drilling fluids, which contain several heavy components including lead, cadmium, mercury, and arsenic. Some of these heavy materials can discharge into the sea, which is not allowed especially in the case of oil-based drilling fluid. The supply of barite is geographically limited, with high transportation costs. To overcome the high cost, shortage, and common problems of barite, an alternative weighting material, ilmenite (5 µm), is introduced which is heavier than barite and more stable at high temperature. Also, the micronized ilmenite was introduced to overcome the ECD challenges in some drilling operations at reasonable cost. Extensive lab work was done in order to: 1) optimize the rheological properties of the drilling fluid, 2) determine the optimum pH that gives stable dispersion, 3) assess the thermal stability, 4) optimize the filtration parameters (filtrate volume and filter cake thickness), and 5) characterize the ilmenite-based filter cake. Zeta potential results showed that ilmenite was stable when mixed with water at a pH above 7 and it was dispersed and stable when mixed with the drilling fluid components. Drilling fluids have a density range from 100 to 120 pcf and a plastic viscosity of 28–32 cp. No phase separation was observed after hot rolling for 16 hrs at 300°F. The optimized water-based drilling fluid formula had a small filtrate volume (12 cm3) and thin filter cake (0.2 in.) under dynamic conditions. SEM analysis showed that ilmenite filter cake was heterogeneous and contained ilmenite particles in the layer closer to the rock surface. The layer closer to the drilling surface had a mixture of xanthan gum and modified starch, which were used to optimize the rheological properties at 250°F. This study will provide a complete evaluation of the drilling fluids with ilmenite as a weighting material and will help drilling engineers to better design drilling fluids for HPHT wells.

Paper presented at SPE 156451, IADC/SPE Asia Pacific Drilling Technology Conference (APDT), 9-11 July, 2012, Tianjin, China.

Abstract

Manganese tetraoxide is used as a weighting material in drilling deep wells (> 90 lb/ft3). Removal of the filter cake that contains Mn3O4 is a difficult task. This is mainly because Mn3O4 is a strong oxidizing agent. Extensive lab work was done to: 1) study the reaction of glycolic acid with Mn3O4 particles (D50 =1 μm) as a function of time at 190°F in a batch reactor, 2) examine the solubility of the filter cake using a modified HP/HT filter press, 3) determine the compatibility and thermal stability of cleaning fluids with α-amylase using an HP/HT visual cell, 4) characterize the filter cake using computer tomography (CT), and 5) assess the retained permeability of limestone and sandstone cores. The results following the removal of the filter cake showed that 4 wt% glycolic acid (4 g Mn3O4 to 200 ml acid solution) dissolved 75 wt% of Mn3O4 particles at 190°F. Glycolic acid (5 wt%) had a removal efficiency of 85 to 90% of manganese tetraoxide-based filter cake after 20 hrs soaking time. The retained permeability was 100% for the Indiana limestone core and 125% for the Berea sandstone cores. CT results showed that glycolic acid was able to stimulate the cores and no formation damage was observed.

Paper presented at SPE Deepwater Drilling and Completions Conference, Galveston, Texas, USA, June 2012.

Abstract

Hydrochloric acid, organic acid, or a mixture of these acids is used to remove filter cake, which consists mainly of calcium carbonate. However, the use of these acids in horizontal and deep wells has some major disadvantages, including high and uncontrolled reaction rate and corrosion to well tubular. To overcome these problems, chelating agents are used in oil and gas wells. Extensive lab studies were done to determine: 1) the compatibility of various chelates with α-amylase at different pH values, 2) the optimum pH that should be used to remove filter cake, 3) the efficiency of filter cake removal using a modified HPHT filter press, 4) the return permeability of sandstone and limestone cores, and 5) assess the potential of formation damage using a computer tomography scanner. All of these tests were conducted at temperatures up to 225°F. The results obtained showed that chelate solutions, GLDA (pH of 3.3 – 13) and HEDTA (pH 4 and 7) were incompatible with α-amylase solutions over a wide range of temperatures. At high pH, various chelates had removal efficiency of 40% and retained permeability of 30%, which indicated formation damage. To solve this problem, 20 wt% of the chelating agents at low pH (3.3 – 4) were used to remove the filter cake without the enzyme stage. The results obtained showed that the retained permeability increased to 85% for limestone cores and 110% for sandstone cores. The removal efficiency of the filter cake was 100% for limestone and sandstone cores. CT results showed that no formation damage was observed when using chelating agents as a breaker to remove the filter cake.

Elkatatny, S.M., Mahmoud, M.A., and Nasr-El-Din, H.A.
Paper presented at DOI: 10.2118/144098-pa, SPE Drilling & Completion 27 (2): pp. 282-293, 2012.

Abstract

Filter-cake characterization is very important in drilling and completion operations. The homogeneity of the filter cake affects the properties of the filtration process such as the volume of filtrate, the thickness of the filter cake, and the best method to remove it. Various models were used to determine the thickness and permeability of the filter cake. Most of these models assumed that the filter cake was homogeneous. The present study shows that the filter cake is not homogeneous, and consists of two layers of different properties. The objective of this study is to measure the filter-cake thickness and permeability of water-based drilling fluids by a new approach and compare the results with previous models. A high-pressure/high-temperature (HP/HT) filter press was used to perform the filtration process under static conditions (225°F and 300 psi). A computed-tomography (CT) scan was used to measure the thickness and porosity of the filter cake. Scanning electron microscopy (SEM) was used to provide the morphology of the filter cake. The results obtained from the CT scan showed that the filter cake was heterogeneous and contained two layers with different properties under static and dynamic conditions. Under static conditions, the layer close to the rock surface had a 0.06-in. thickness, 10- to 20-vol% porosity, and 0.087-pd permeability, while under dynamic conditions, this layer had a 0.04-in. thickness, 15-vol% porosity, and 0.068-pd permeability. The layer close to the drilling fluid had a 0.1-in. and 0.07-in. thickness under static and dynamic conditions, respectively, and it had zero porosity and permeability after 30 minutes under static and dynamic conditions. SEM results showed that the two layers contained large and small particles, but there was extremely poor sorting in the layer, that was close to the drilling fluid, which led to zero porosity in this layer. Previous models underestimated the thickness of the filter cake by almost 50%. A new method was developed to measure the thickness of the filter cake, and various models were screened to identify the best model that can predict our permeability measurements.

Paper presented at SPE 154192, SPE EUROPEC Conference, 4-7 June, 2012, Copenhagen, Denmark.

Abstract

Water-based drilling fluids consist of xanthan gum, starch, sized calcium carbonate and salt particles to increase mud density was used to drill horizontal wells. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, and chelating agents are limited at certain conditions. A drilling fluid was designed based on calcium carbonate particles and an ester of lactic acid. The objective of the latter is to remove calcium carbonate once the drilling operation is complete and there is a need to remove the filter cake. Extensive lab work was done to; 1) determine thermal stability of the drilling fluid (70-72 pcf) for 24 hrs, 2) characterize the filter cake using a computer tomography, 3) assess potential formation damage for different rock types (limestone and sandstone) using a modified HPHT filter press, and 4) determine the removal efficiency of the filter cake and the return permeability. The results obtained showed that the drilling fluid has stable rheological properties up to 300oF over 24 hrs. CT scan showed that the filter cake contained two layers, one layer closed to the rock surface, which contained a mixture of calcium carbonate and acid-precursor and one layer closed to the drilling fluid that contained a mixture of XC-polymer and starch. The polymer layer was removed by using 10% solution of alpha amylase. The rest of the filter cake was removed by lactic acid that was produced from the hydrolysis of the ester. The removal efficiency of the filter cake was nearly 80% and the return permeability was about 100%. The decrease in CT number of the core after the removal process indicated that the filter cake was completely removed. This paper will discuss the development of this new drilling fluid and will give recommendations for field applications.