Oil-bearing Formations Research Articles

Petrophysical evaluation of low-resistivity sandstone reservoirs with nuclear magnetic resonance log

The combination of conventional logs, such as density, neutron and resistivity logs, is proven to be very effective in the evaluation of normal reservoirs. For low-resistivity reservoirs, however, an accurate determination of the petrophysical parameters with the conventional log reservoirs is very difficult. This paper presents two cases of low-resistivity reservoirs and low-contrast resistivity reservoirs, where conventional logs fail to determine the petrophysical properties of reservoirs, mainly, low-resistivity and low-contrast resistivity reservoirs. The problems of these reservoirs are that conventional logging interpretation shows high water saturation zones, but water-free hydrocarbon would be produced. In the case of low-resistivity contrast reservoirs, it is very hard to determine water hydrocarbon contact with resistivity logs. Nuclear magnetic resonance (NMR) has only been available as a supplementary tool to provide additional information on the producibility of the reservoir. The main limitations of NMR have been the cost and time of acquiring data. This paper shows that in the case of low-resistivity reservoirs, NMR is a very cost-effective tool and is of help in accurately determining the reservoir rock petrophysical properties. In the analysis of NMR data, several aspects of NMR technique have been used: (1) T1/T2 ratio for fluid identification, (2) the difference between NMR-derived porosity and total porosity to determine the types of clay minerals, (3) NMR relaxation properties to identify fluids composition and rock properties. This paper presents four examples of low-resistivity reservoirs. Analysis of the NMR data of low-resistivity reservoirs has helped identify the producibility of these zones, determine lithology-independent porosity and distinguish between bound and free water. For the case of low-contrast resistivity reservoir, where there was little resistivity contrast between water-bearing formation and oil-bearing formation, NMR has been able to identify the fluid composition of the two formations, as well as the height of the oil column. This was based mainly on the high contrast of NMR relaxation parameters.

A study of image autocorrelation as a method to characterize porosity and estimate permeability

Ioannidis, et al., published a statistical methodology for analyzing of porous microstructure to estimate permeability in the Journal of Petroleum Science & Engineering. The method is based on the calculation of the autocorrelation function from binary images of porous space. This paper presents a systematic application of the methodology applied to twenty-three sandstone samples from a Colombian oil bearing formation. Images of porosity were acquired under different detection conditions in order to carry out a comparative evaluation of the results at different resolutions. It was found that the adjustment parameters for the autocorrelation function, as well as its derivative and integral, dependent strongly upon the conditions of image detection. Under conditions of maximum resolution, permeability was estimated within the same order of magnitude of the value measured experimentally, with an accuracy that varies from 1.6% to 24%.

Limiting Atmospheric CO 2

W orldwide emissions of CO2 continue to increase, and prudence dictates that technologies be developed to help limit this trend. One of several ways to attenuate the increase of CO2 in the atmosphere is to sequester it.[*][1] The technology for doing so exists. The injection of CO2 into oil fields is having economically beneficial effects while at the same time sequestering CO2. In addition, under the surface of the earth in the United States and elsewhere, many structures that once were filled with fossil fuels have been exploited, leaving space that might be used to store CO2. In the United States, some of the structures from which natural gas has been extracted are being used to safely store high-pressure gas produced elsewhere. In the exploitation of petroleum fields, about 20 to 40% of the oil can usually be obtained. In the early days, production was often enhanced in neighboring wells when water was forced down into one of them. Later it was discovered that CO2 under pressure was also effective. In many oil wells, pressures and temperatures are high enough that CO2 becomes a mobile fluid that is miscible with oils having densities of about 0.90 grams per cubic centimeter or less. These liquids tend to move toward lower pressures in production wells, and with this technique an additional 10 to 15% of the oil in an oil field can often be produced. Much of the CO2 is recycled, but part of it remains in the oil-bearing formations. The net result can be profitable use of CO2 and sequestration of some of it. In the United States in 1998, CO2 had a major role in producing 6% of domestic crude oil. Later this year, a project using CO2 will begin at Weymouth Sasketchawan in Canada. A field there that has been producing oil since 1952 will receive 5000 metric tons of CO2 per day via a 300-kilometer pipeline. The source will be the Dakota Gasification Company, located in Beulah, North Dakota. During the course of a multiyear injection, 20 million metric tons of CO2 will be sequestered, and an extra 130 million barrels of oil will be produced. An international team will monitor the behavior of the field, and details of their findings will be made widely available. Another benefit could be that more attention will be focused on the Dakota Gasification Company. Among the plant's other outputs are electricity, methane, hydrogen, ammonium sulfate, phenols, and cresols. Its principal inputs are liquid oxygen, steam, and lignite coal. Almost all of the efforts to use CO2 in enhanced oil recovery have occurred in the United States. A notable exception is a large Bati Roman field in southeast Turkey. Its heavy oil has high-molecular-weight components, and primary production was capable of achieving an ultimate recovery of only 1.5% of the original oil. Injection of CO2 was successful in increasing production. Total miscibility was not achieved, but a large volume of CO2 dissolved in the oil and its viscosity decreased from 1000 centiposes (cp) to less than 100 cp. This facilitated flow, and a recovery of 6.5% is expected. The present amount of geological sequestration of CO2 is small in comparison with emissions. However, the ultimate global potential is substantial. In addition to its use in petroleum fields, a substantial volume of CO2 could be sequestered in deep unmineable coal and in depleted natural gas fields. A 131-page report commissioned by the International Energy Agency (IEA) and supported in part by the U.S. Department of Energy has included estimates of what might ultimately be achieved. [†][2] The IEA report estimates that the ultimate storage capacity of the oil and gas fields equates to over 125 years of total current CO2 emissions from fossil-fueled power plants. A major source of CO2 is the combustion of fossil fuel in power plants. Coal is the major and the cheapest fuel, but CO2 formed by burning it is polluted. The gas must be cleaned and pressurized before injection. The total cost of these procedures is roughly $53 per metric ton or more. This cost is a barrier to segregating it. A vigorous program aimed at cutting the cost of cleaning CO2 emitted by power plants should have a high priority and adequate funding. Success in such a program would be an important help in reducing the overall costs of whatever sequestration methods were ultimately employed. Controversy exists about the possible extent of the contribution of CO2 to present and future global warming. However, if international agreements are implemented to attenuate the buildup of atmospheric CO2, sequestration of it in unused or abandoned fossil hydrocarbon fields is one good step to take. [1]: #fn-1 [2]: #fn-2

00/00674 Hydrologic cells for recovery of hydrocarbons or thermal energy from coal, oil-shale, tar-sands and oil-bearing formations

00/00674 Hydrologic cells for recovery of hydrocarbons or thermal energy from coal, oil-shale, tar-sands and oil-bearing formations

Adsorption of Benzoic and 4-Heptylbenzoic Acid on Different Silica Substrates from Organic and Aqueous Solution

In studies of the adsorption of surface-active molecules from organic phase on mineral surfaces in relation to wettability alterations, the system has normally been made water-free. However, since water is an inherent part of all oil-bearing formations, it is of interest to study adsorption in solid/water/oil systems. In this paper we therefore study the adsorption of benzoic (BzCOOH) and 4-heptylbenzoic (4-HBA) acid from organic solution on different silica substrates in the presence of water. The results show that the adsorption is enhanced in the presence of water and that 4-HBA has a higher affinity for the silica surface than does BzCOOH. Variations in the surface properties of the silica substrates had no significant effect on the adsorption. In studies of the adsorption of organic acids from aqueous phase, the acid has been added either as the corresponding acid salt or as the acid itself. However, the adsorption behavior of the acid salt is not necessarily representative of the adsorption behavior of the acid. To investigate this more closely, we studied the adsorption of benzoic acid added to water both as sodium benzoate (BzCOO−Na+) and as BzCOOH. The results revealed a significant increase in the maximum adsorption when BzCOO−Na+ was used as adsorbate instead of BzCOOH.

Compaction Measurements in Oil-Bearing Formations of the San Joaquin Valley

Compaction Measurements in Oil-Bearing Formations of the San Joaquin Valley

Special Core Analysis Designed to Minimize Formation Damage Associated With Vertical/Horizontal Drilling Applications

Abstract Laboratory testing of core material to optimize drilling fluid composition and procedures has been used for many years to minimize invasive formation damage of a mechanical, chemical or biological nature which can occur during the drilling of horizontal or vertical wells. This paper discusses the limitations of past practices such as the use of non-representative core or fluids, non-preserved or non-restored state core, ambient conditions of temperature and overburden pressure, direct injection of muds/filtrates into samples and unrealistically high drawdown gradients for cleanup. The paper describes the current technology used to eliminate many of these concerns and also to extend drilling fluid evaluation technology to extremely heterogeneous carbonate and sandstone formations, fractured formations and specific test equipment and procedures used to evaluate the effectiveness and utility of underbalanced drilling programs. Introduction Formation damage occurring during the drilling of horizontal or vertical wells can be a significant cause of ultimate reduced productivity in both oil and gas bearing formations. In some cases a combination of petrographic and special core analysis techniques is used to evaluate the potential effectiveness of proposed drilling fluids and procedures, prior to incurring the actual cost and risk of implementation. These tests are conducted to obtain a better assessment of the risk associated with the use of proposed drilling fluids and to optimize the fluid and procedures which will be utilized in a given horizontal or vertical well operation to maximize ultimate productivity of oil or gas. Considerable advances have been made in recent years in both the execution and interpretation of the results of laboratory coreflow tests to obtain representative results for effective field design of well drilling programs. This paper reviews test procedures used in the past, describes potential problems with these test procedures, and outlines current laboratory technology with respect to specialized laboratory testing to evaluate drilling induced damage for vertical and horizontal well applications. Common Mechanisms of Formation Damage During Overbalanced and Underbalanced Drilling Operations A number of authors have provided a detailed discussion of potential formation damage mechanisms which may occur during overbalanced and underbalanced drilling operations. A summary of this work is provided in the literature(l-31). These mechanisms include: Mechanically Induced Formation Damage Physical migration of in situ fines and mobile particulates. The introduction of extraneous solids of either an artificial nature (i.e., weighting agents, fluid loss agents, or artificial bridging agents) or naturally occurring drill solids generated by the milling action of the drill bit on the formation. Relative permeability effects associated with the entrainment of extraneous aqueous or hydrocarbon phases within the porous medium. Formation damage effects associated with the use of extreme underbalance or overbalance pressures and associated fines migration or spontaneous imbibition phenomena. Direct mechanical glazing phenomena associated with bitformation interactions. This particular damage mechanism is usually associated with gas drill operations where high bitrock temperatures commonly occur.

Field Testing of the Formation Heat Treatment Process

Abstract A novel matrix stimulation concept, formation heat treatment (FHT), which involves the application of intense heat for the treatment of water-blockage and clay-related formation damage in water-sensitive formations was developed and tested in the laboratory. Initial bench-scale heating tests on water-sensitive sandstone cores showed that heat treatment at 600 ° C can improve air permeability of a damaged core by 50% above the initial permeability. Dramatic permeability increases of 750% and 1,000% above the initial reservoir permeability occurred at 800 ° C for the cores taken from the gas- and oil-bearing formations, respectively. To prove the FHT technology in the field, an electrical downhole heater was designed and constructed. After testing the heater on surface, the heater was lowered into the target reservoir, 1.5 km downhole, heated up and retrieved from the wellbore. Results of the field test showed that there was a significant increase in the post heat-treatment gas injectivity. To quantify the heating effect, pressure transient analyses on pressure falloff data were carried out and the post heat-treatment permeability was found to increase by several fold. The field logistics and the field test results are presented in this paper. Introduction Most hydrocarbon-bearing (oil and gas) sandstone reservoirs contain clay materials, which have the tendency to swell in contact with water-based foreign fluids or to migrate due to fluid velocity in the pore spaces. Operations such as drilling, completion, workovers, and stimulation often expose the formation to a foreign fluid and cause formation damage. Such damage is usually more severe in horizontal wells, because of the longer exposure of the wellbore to the offending fluids(1). During the drilling and completion phases, the primary mechanisms of near-wellbore formation damage can be explained by the following factors:Pore-throat constriction, caused either by clay swelling due to incompatible fluids or by clay migration,Water blocking due to reduction in relative permeability to hydrocarbon,Plugging with drill solids and mud products, andLoading of the reservoir with drilling or completion fluids. Formation damage during drilling and completion has long been identified as a major problem. Preventive measures to stabilize clay swelling and migration, mostly consisting of the use of various chemicals (e.g., KCl) in the drilling or completion fluid, have been discussed in the literature(2-7). However, prevention of clay damage is not always possible or effective, and curative measures may then become necessary. Several curative methods have been attempted and presented in the literature(8-15). The most popular stimulation technique is hydraulic fracturing. This method is not always applicable or desirable (e.g., in water or gas-flooding situations, zones containing active bottom water or gas caps) or not economical (e.g., in some horizontal wells). Another approach is to stimulate the near-wellbore region using acids, which dissolve either the clay minerals themselves (HF acid) or the surrounding formation rock (HCl and HF acids). Matrix-stimulation techniques using acids have been applied to carbonate reservoirs for productivity improvement. In both hydraulic-fracturing and acid-stimulation techniques, the proper design of the fluid system is very important.

Injection-induced Microseismicity in Colorado Shales

Imperial Oil Resources Limited uses cyclic steam stimulation to recover oil from their Cold Lake oil field in Alberta. This operation, in particular situations, can be associated with the failure of well casings in the Colorado shales above the oil-bearing formation. A number of fluid injection operations was undertaken at this site and the associated microseismicity was detected using two three-component geophones and fifteen hydrophones. The purpose of this experiment was to simulate the occurrence of a casing failure, determine the feasibility of monitoring in a shallow environment, and characterize the microseismic activity. A calibration survey provided values of 1786 ± 108 m/s for P-wave velocity, 643 ± 56 mks for S-wave velocity and 0.428 ± 0.017 for Poisson’s ratio in the shale formation. Estimates of the quality factor Q P were 15 for the horizontal direction and 38 for the vertical direction, corroborating the evidence of velocity anisotropy. Calibration shots were located to within 10 m of the actual shot points using triangulation and polarization techniques. Several hundred microseismic events were recorded and 135 events were located. The results showed that microseismic activity was confined to depths within 10 meters of the injection depth. The experiment clearly established the feasibility of detecting microseismicity induced by fluid injection rates typical of casing failures in shales at distances over 100 m.

Application Of Core Analysis Data For Formation Evaluation

The primary goal of most reservoir evaluation studies is the integration of data from various sources to indentify zones with similar fluid flow characteristic, and to define the areal and lateral continuity of such zones. Core data developed on rock samples recovered from a formation or interest zone which a play vital role in exploration programs, well completion and workover operations and in well and reservoir evaluation. Coring is the only mean of obtaining an actual sample of an oil bearing formation to study. These cores, with proper handling and preservation, are used to obtained data which permit accurate evaluation of the oil or gasreservoirs. This paper presents a practical used of core analysis data for formation evaluation of reservoir hydrocarbon and to provide information that will be of practical value to geologists and engineers involved with the interpretation of core analysis data.

Heat Treatment For Clay-related Near Wellbore Formation Damage

Abstract During drilling and completion, the primary mechanisms of near-wellbore formation damage include pore throat constriction, water blocking, plugging with drill solids and mud products, and loading of the reservoir with drilling or completion fluids. Among these mechanisms, some of the most severe ones encountered in clastic reservoir applications are the pore throat constriction due to clay swelling, and water blocking resulting in a reduction in the relative permeability to hydrocarbons A novel matrix stimulation concept which involves the application of intense heat for the treatment of water blockage and clay related formation damage in water sensitive formations is presented in this paper. Bench-scale heating tests were carried out on water sensitive sandstone cores to determine the effect of heat on effective permeability, fluid saturation, and mineralogy (i.e., degradation of in situ minerals). Results indicated that heat treatment at 600 °C can improve air permeability of a damaged core by about 51% above the initial permeability. Dramatic permeability increases of 764% and 988% above the initial reservoir permeability occurred at 800 °C for the cores taken from the gas- and oil-bearing formations, respectively. Introduction Formation damage can occur at any time during a well's history from the initial drilling and completion of the wellbore through the depletion of the reservoir during production. Operations such as drilling, completion, workovers, and stimulation, which expose the formation to a foreign fluid, may cause formation damage because of adverse wellbore-fluid to formation interactions. Such damage is usually severe in horizontal wells, because of the longer exposure of the wellbore to the offending fluids(1). During the drilling and completion phases, the primary mechanisms of near-wellbore formation damage can be explained by the following factors:pore throat constriction, caused either by clay swelling due to incompatible fluids or by clay migration,water blocking due to reduction in relative permeability to hydrocarbon,plugging with drill solids and mud products, andloading of the reservoir with drilling or completion fluids. Clay related formation damage during drilling and completion has long been identified to be a major problem. Preventive measures to stabilize clay swelling and migration, mostly consisting of the use of various chemicals (e.g., KCl) in the drilling or completion fluid, have been discussed in the literature(2–7). However, prevention of clay damage is not always possible or effective, and curative measures may then become necessary. Several curative methods have been attempted and presented in the literature(8–15). Non-thermal Curative Processes One approach is to bypass the near wellbore damage using hydraulic fracturing. This technique is very effective in sandstone formations and in vertical wells. However, there are situations where hydraulic fracturing is not desirable (e.g., in water or gasflooding situations, zones containing active bottom water or gas caps) or not economical (e.g., in some horizontal wells). Another approach is to stimulate the near wellbore region using acids, which dissolve either the clay minerals themselves (HF acid) or the surrounding formation rock (HCl and HF acids).

An innovative technique resolves apparent anomalies in detection of gas zones based on neutron—density logs

Cross-over effect on neutron—density logs often indicates gas-bearing sands and/or carbonates. Identification of gas based solely on the neutron—density response can be misleading because some gas producing formations may not display a significant (or any) neutron—density cross-over, and some oil-bearing formations may falsely exhibit an appreciable neutron—density cross-over. False gas effects arise from either silt/shale in the reservoir, or from a significant difference between the reservoir matrix density and the standard sandstone/limestone matrix scale generally employed on the density log. True neutron—density gas cross-over effects occur in non-argillaceous formations when the matrix density of the reservoir closely matches the matrix density on the bulk density log. Examples of false gas effects are illustrated in two newly discovered fields, H-field and K-field, in Upper Assam, India. The reservoir in H-field produces gas from a silt—sand sequence, and when the percentage of silt in the reservoir approaches a certain upper limit (about 18%), no cross-over effect is seen in gas-bearing sands on the neutron—density log. An equation has been developed to correct for the presence of silt before making inferences about the presence of gas from neutron—density logs. The second field, K-field, produces oil from thin sands that are typically less than 3 m thick, and false gas effects can be seen on the neutron—density log. The false gas cross-over is caused by a reservoir matrix density that is considerably lower than the standard non-argillaceous sandstone matrix density scale on the bulk density logs. A combination of cross-plots and laboratory measurements is used to derive a modified matrix scale that corrects for false gas effects in the K-field reservoir. These two field case examples in Upper Assam, India, demonstrate that interpretations from wireline logs may be misleading and that correct log analysis requires integration of geology, subsurface test results and production data.

Well-slot method for degassing coal beds in which the rock pressure has not been discharged

A method developed at the Mining Institute (Siberian Branch of the Russian Academy of Sciences) for directional fluid fracturing (DFF) of rock masses can be used to create an extended slot in the rock mass in a single operation. This is done by introducing a specially designed mechanism into the well at the required depth; this mechanism cuts an initiating slot of the required size and shape into the rock at the wall of the well. Through a sealing device, a fluid is fed under pressure to the initiating slot; the fluid may be any substance that will flow, including water. When a critical pressure of the fluid is reached, the frontal part of the initiating slot is moved from place; and, as it grows in the assigned direction, it is converted to an extended, large-area slot. Information on the essence of the DFF method and results of tests in coal and hardrock mines have been presented in scientific reports and a number of articles published in the period from 1982 to 1996, mainly in the present journal (Fiziko-Tekhnicheskie Problemy Razrabotki Poleznykh Iskopaemykh). A slot that is being created in a rock mass can be given various properties. In the particular case with which we are concerned, it must have the property of a highly porous collector that is capable, in the ftrst place, of draining the surrounding mass and, in the second place, of transporting the gas through the slot/collector to the well and then to the gas line. If the creation of an extended slot in various rock masses is performed repeatedly, then the subsequent work must resolve the problem of efficient filling of the slot with solid granular material. Apart from the concepts themselves, in our case we can use practical experience in hydraulic fracturing operations in coal beds and oil-bearing formations. Here it is appropriate to note the main difference between the method of conventional hydraulic fracturing [1] and the DFF method [2]. In the first case, the liquid is propagated only along natural exogenic and endogenic cracks, which are for the most part large and are randomly oriented in space; therefore, we can hardly consider that area degassing of a coal bed through wells at a distance from each other will be accomplished uniformly. This is illustrated graphically by circle charts that have been plotted for the natural fracturing with the imposition of cracks formed by hydraulic fracturing, and also by sketches made repeatedly of the actual zones of hydraulic fracturing of beds after they have been exposed by underground mining operations [1]. In the second case, when it is proposed to use the method of directional fluid fracturing [2], there is created in a single operation just one extended slot that is located in space in such a place and such an orientation that the process of degassing a gasbearing coal bed will be accomplished uniformly. This requirement is satisfied to the greatest degree by the location of a large-area slot within the seam and along its bedding. A qualitative evaluation of the degassing capacity of a slot can be obtained from an analysis of the simplest Darcy formula

Fluid Design to Minimize Invasive Damage In Horizontal Wells

Abstract Formation damage is a very reservoir specific process, but extensive studies indicate that generalities can often be drawn with respect to certain types and mechanisms of damage which are more prevalent with various reservoir types. This paper provides a mechanistic discussion of various types of formation damage common to horizontal wells, such as fluid-fluid and rock-fluid incompatibilities, solids invasion, effect of overbalance pressure, aqueous phase trapping, chemical adsorption, wettability alteration, microbiological activity, and fines migration. These phenomena are discussed and how they specifically relate to the following formation types:Clean and dirty homogeneous sands.Clean and dirty laminated sands.Unconsolidated sands.Fractured sands.Homogeneous carbonates.Fractured carbonates.Vugular carbonates. Recommendations for various fluid types and procedures which have experienced success in certain situations are also presented. Laboratory testing of fluids and representative core samples is highlighted as a potential diagnostic tool to select the optimum fluids for drilling, completion, stimulation and workover treatments. Use of these guidelines can, in many cases, narrow the choice of potential fluids considered for use in a given lithofacies type and increase the efficiency of the optimization process. Introduction Horizontal drilling is being utilized in an ever increasing fashion to exploit reservoirs exhibiting thin pay zones, problems with water or gas coning, to obtain greater reservoir exposure and to maximize the productive potential of naturally fractured reservoirs. Reductions in the productivity of these horizontal wells due to improperly or inadequately designed drilling, completion or workover programs is a frequent occurrance. This paper documents common areas for potential reductions in the productivity of horizontal wells completed in oil or gas bearing formations due to invasive formation damage and provides general criteria for the design and selection of fluids and operating programs to minimize potential damage. Invasive Formation Damage Formation damage can be described as any phenomenon induced by the drilling, completion or stimulation process or by regular operations resulting in a permanent reduction in the productivity of a producing oil or gas well or the reduction in the injectivity of a water or gas injection well. Invasive formation damage can occur by the introduction of:Foreign potentially incompatible fluids into the formation.Natural or artificial solids.Extraneous immiscible phases.Physical mechanical damage. Further information on some of the specific mechanisms of these various types of invasive damage will be elucidated upon later in the paper. Formation Damage in Horizontal vs. Vertical Wells A detailed discussion of mechanisms of formation damage in horizontal wells has been presented in the literature(1). Formation damage tends to be more significant in horizontal vs. vertical wells for a number of reasons, some of these being:Longer fluid exposure time to the formation during drilling and greater potential depth of invasion in situations where sustained fluid and solids losses to the formation are apparent.

Horizontal Well Cyclic Combustion, Wabasca Air Injection Pilot

Abstract Amoco Canada Petroleum Co. Ltd. and Alberta Department of Energy (Oil Sands & Research Division) are currently testing a novel combustion-related heavy oil recovery scheme utilizing horizontal wells in a thin pay horizon in the Wabasca area. The pilot is located approximately 250 km north of Edmonton, Alberta, at the south end of the Wabasca oil sands deposit. Primary production utilizing horizontal wells has proven economic in the area but the expected recovery is only 5 – 10%. The combustion pilot utilizes a central horizontal air injection well with two outside producing horizontal wells. This is a unique system in that it is the first time a horizontal well has been used as an air injector. All three horizontal wells were initially placed on primary production. The central horizontal injection well was then preheated with steam and ignited with air. Once air injection was terminated, production commenced from the two outside horizontal wells. Production response to date has been favourable in this first cycle due to the reservoir repressurization that has occurred. This enhanced oil recovery process may allow industry to economically extend the production of thin pay reservoirs beyond primary depletion. Introduction The Wabasca In Situ Horizontal Combustion Project is located approximately 250 km north of Edmonton, Alberta, at the south end of the Wabasca oil sands deposit as shown in Figure 1. The main oil bearing formation is the Wabiskaw ‘A’ sand with an average reservoir thickness of 5 m. The API gravity of the oil is 14 ° and the viscosity is between 5,000 - 10,000 cp at a reservoir temperature of 15 °C. Other reservoir parameters are shown in Figure 2. Amoco Canada holds approximately 60 sections of oil sands leases in the immediate pilot area. The first two primary horizontal wells were drilled in 1988. Currently, Amoco has a total of 12 horizontal wells which have been drilled for primary production. Primary recovery with horizontal wells is economic but is only estimated to produce 5 – 10% of the original oil in place. Amoco Canada has initiated a cyclic combustion pilot utilizing three horizontal wells (see Figure 2). There is a central horizontal injection well flanked on either side by horizontal producing wells. After a period of primary production from all three wells, the injection well was preheated with steam, then ignited with air. Initial production results from the flank wells in the first cycle have yielded promising results to date, due to the reservoir repressurization that has occurred. The results and conclusions reported in this paper are based on pilot operations to December 1994. History Vertical wells in the Wabasca area have been unsuccessful both from a primary and enhanced oil recovery perspective. Primary production rates have been low (on the order of 1 to 2 m3/d) and cyclic steaming, electrical wellbore heating and conventional fireflooding have failed to yield commercially viable results. Since 1988, Amoco Canada and CS Resources (which is the other major operator in the area) have been pursuing horizontal well primary production as a means of economic reservoir development.

Electromagnetic Stimulation of Lloydminster Heavy Oil Reservoirs: Field Test Results

Abstract The paper will present the field test results of two electromagnetic (EM) stimulation projects conducted in the Lloydminster heavy oil area. The two wells (AI-11-4B-25 W3M Lashburn and AB-6-51-27 W3M Northminster) produce heavy crude from the Sparky formation. Detailed production, electrical and operational data was gathered and analysed to quantify the effect EM stimulation had On each well's producing characteristics. The main areas covered by the paper include production characteristics (primary and enhanced), in-flow performance relationships (primary and enhanced), operational considerations and some of the related economics. The data discussed to this point has been restricted to reservoir heating. An additional review of a tubing heating electrical configuration test (ran on the Lashburn well) has been -included. The viscous nature of the crude oil being produced caused severe rod fall problems. Tubing heating was initiated to reduce the wellbore fluid viscosity and eliminate the rod fall problem. The paper will conclude with a general overview of the EM stimulation process as applied to the Canada Northwest Energy Limited-locations and the potential for future applications. Introduction The possibility of using electrical energy to heat oil-bearing formations has been attempted on several occasions over the past four decades, In general terms, the electrical (and electromagnetic) energy is converted to heat. Three basic types of heating are possible (dielectric, inductive and resistive). This discussion will deal with the resistive heating process. Canada Northwest Energy Limited et al. (CNW) contracted with EOR International (EOR) to field test the process in the Lloydminster area heavy oil formations. A majority of the heavy oil sands around Lloydminster are well suited to the application of electromagnetic (EM) heating. Many of the formations are relatively thin and not well suited for other secondary, tertiary and thermal recovery methods. The EM heating process as applied in the CNW pilot areas creates a heated zone in the near wellbore region, The application of heat significantly reduces the viscosity of the oil, improves the oil/water flow characteristics, and overcomes some forms of formation damage. The end result is an improved pressure profile in the near wellbore region and a corresponding increase in the oil production rate. Field Evaluations Introduction The electromagnetic (EM) heating process was tested in three Canada Northwest Energy Limited project areas (Wildmere, Northminster and Lashburn). The pilot projects (as listed above) were not economically successful (due to premature equipment failure). They did however provide very encouraging technical information from a reservoir engineering point of view. The electrical delivery system used in these projects consisted of externally insulated casing. The casing was electrically isolated from the wellhead and tubulars. The casing insulation was scraped off across from the reservoir to allow EM energy to enter the formation. The energy flow was into the reservoir and up through the overburden to surface ground wells to complete the circuit.

Chemical and isotopic examination of produced waters from the BP-Wolf lake in situ combustion pilot

The chemical and isotopic compositions of co-produced waters can be used to monitor the processes that take place during in situ combustion. Anticipated processes include mixing of waters, production of CO 2, production of high concentrations of dissolved sulphate and variations in water chemistry associated with heated zones. Water sources include pore waters in oil-bearing strata, waters in overlying or underlying aquifers, water condensed from previously injected steam, and waters associated with combustion. Waters from all sources may mix during production and interpretation of the combustion process can be refined by an understanding of water sources. Produced fluids from the BP-Wolf Lake pilot site in Alberta have been examined to evaluate the effectiveness of the chemical composition of water and the isotopic compositions of aqueous species for monitoring in situ combustion. Produced waters do not show simple conservative mixing behaviour. This suggests that multiple sources of water and other processes, including water-rock reactions, act to modify water compositions. At least three sources of produced waters can be recognized and these are interpreted to be formation water, injected steam and waters that have low Cl and high HCO 3 due to combustion. It is not possible to distinguish waters in the oil-bearing formation from regional waters present in aquifers that underlie the stimulated intervals. Dissolved aqueous species, such as SiO 2, Na, K (as Na/K) and Cl can be used to monitor the approach of the combustion front. Sulphate has been suggested as an indicator of approaching combustion and, although sulphate concentrations rise as combustion approaches a producing well, this indicator is not reliable in all cases. The use of all the above chemical parameters is recommended for detection of combustion zones during operation. The isotope composition of produced waters confirms that there has been significant water-rock interaction during combustion. Carbon isotope compositions of HCO 3 that range from −8 to −25% δ 13C show that oil oxidation is a major contributor of CO 2 at high temperatures, but CO 2 produced by carbonate mineral dissolution becomes more significant as temperature decreases. Sulphate concentrations in waters produced during combustion can be an order of magnitude higher than those observed during steam stimulation. Both the oil (bitumen) and pyrite (FeS 2) are significant sulphur sources. Typically, the sulphur in both phases is in a reduced state and is available through oxidation associated with combustion. The δ 34S of dissolved sulphate in produced waters does not unequivocally identify either of the two major sources of sulphur. However, the relatively depleted δ 34 values for SO 4 suggest that the high sulphate concentrations generally associated with the approach of the combustion front result from the oxidation of pyrite.

Recent cross-formational fluid flow and mixing in the shallow Michigan Basin

Ground water with total dissolved solids (TDS) ranging from 10 to > 50 g/L exists at depths between 90 and 140 m in Devonian oil-bearing formations in the shallow Michigan Basin of southwestern Ontario. These formations comprise mainly limestone and dolomite, and the sources of the saline ground water have not been identified previously. Isotopic and major-ion data from ground water from Devonian oil-bearing formations in southwestern Ontario indicate that the highest-salinity fluids were emplaced locally from depths of several hundred meters. During the later stages of, or following, the Wisconsinan glaciation, saline water and petroleum were also emplaced into overlying Pleistocene clay-rich glacial deposits. Isostatic rebound leading to fracturing and enhanced formation permeability due to matrix expansion was probably the primary mechanism that enabled these saline fluids to migrate into discrete areas of the Devonian and Pleistocene formations. The geochemical data presented here support a model involving cross-formational fluid flow from depth occurring vertically on the scale of several hundred meters since glaciation. The hydrogeologic regime in this shallow basinal system must, therefore, be viewed as dynamic, rather than static, to depths of at least 500 m over a time frame of < 100 000 yr. 54 refs., 10more » figs., 2 tabs.« less

Survival mechanisms of hydrogen sulphide-producing bacteria isolated from extreme environments and their role in corrosion

Abstract The presence of thermophilic sulphate-reducing bacteria (tSRB) has been demonstrated in all accessible zones of water injection and oil production areas of three facilities in the North Sea and from open sea situations. We consider that this widespread occurrence indicates an indigenous population of tSRB within oil-bearing formations. The impact of the oil recovery industry on formations, in particular the use of secondary waterflooding of reservoirs, has caused unprecedented fluid movement within these deep subsurface zones. The microflora, disturbed by these processes, likely to be forced into a cyclic rotation from formation, through production facilities and back into the formations after an unspecified residence time in North Sea waters. Representative cultures of tSRBs recovered from the oil facilities have been shown to be able to survive simulated environmental fluctuations such as those imposed by existence in and passage through formations and prolonged exposure to cold seawater conditions. Results presented here indicate that tSRB are highly opportunistic bacteria, able to respond rapidly to change and, most importantly, able to attach to metal surfaces even when in a state of very low metabolic activity.

Development of Pelican Lake Area Using Horizon1tal Well Technologies

Abstract CS Resources has been a pioneer in the use of horizontal wells to develop heavy oil reservoirs. From 1988 to 1991, CS Resources drilled, and currently operates, 17 horizontal wells in a thin, heavy oil pool in the Pelican Lake area in northcentral Alberta. The horizontal wells were drilled in three phases; eight wells, in 1988, five wells in 1989/1990 and four wells in 1991. At each phase of development, well costs improved and productivities increased. The continual improvement in the overall performance and cost effectiveness of the project can be attributed to the focused approach CS Resources takes toward pool development. This paper will discuss the aforementioned phases of development and how knowledge gained from each phase was used to improve performance in subsequent phases. Several significant accomplishments will also be discussed, including:The drilling of the first ever lateral arm off of a horizontal well in Canada.The drilling of an experimental "J" type profile (in an attempt to improve pump performance).The drilling of a horizontal well with a horizontal length/vertical depth ratio believed to be greater than that of any other well ever drilled. Introduction Most of the vertical wells at Pelican Lake had been shut in due to uneconomical Production. In January 1988 when the first eight horizontal wells were drilled in Pelican Lake, Very few horizontal wells have been drilled in Canada. Some discussion of the first eight Well phase is given in References (1) and (2). Use of horizontal well technologies has turned the Project into a technical and economic success a success which can be attributed to CS Resources focused approach To pool development approach used us comprised of three key components:RESEARCH-Considerable technical work was completed prior to each phase of development.COMMITMENT-Some of the first wells drilled sis not perform as well as predicted. The reasons for the under performance were investigated and the project has since become a success.COMMUNICATION-Discussion throughout the project between geology, drilling, reservoir and production disciplines as well as field staff and service companies, has improved overall project understanding. It has also lead to continual cost and productivity improvements. History The Pelican Lake area is located 175 miles north of Edmonton, Alberta (Figure 1). The discovery well, Gulf Pelican 6-9-81-22W4, was drilled in 1978. The main oil bearing formation is the Wabiskaw "A" which has an average net oil pay of 5.0m. The PI gravity of the oil is 14', and the viscosity is between 600 and 100 centipoise at 20 ºC. Formation Sand has an average porosity of 26 and an average horizontal permeability of 3 darcies. During October 1987, CS Resources entered into a farm-out and option agreement with Gulf Canada covering 58 square miles in the Pelican Lake area. Prior to CS Resources acquisition of the subject lands, more than $100 million had been expended in the Pelican Lake area. From 1980 to 1986, approximately 100 vertical and deviated wells were drilled.