Secondary Recovery Projects Research Articles

REACTIVATION AND FUNCTIONAL SHIFT OF SUSPENDED WELLS FOR INJECTION TO INCREASE OIL RECOVERY IN WATERFLOODING PROJECT PLANS

The "BDS" oil field volumetrically has Original Oil in Place (OOIP) of 56.84 MMSTB. This field has produced 20.45 MMSTB with a current recovery factor (RF) value of 35.89%. Because the remaining reserves are still large, this field is still suitable for development. The type of driving force is a water drive with very high water production, where the water cut is more than 95% so that it has the potential to carry out secondary recovery projects using the waterflooding method using reservoir simulation. Optimization is carried out by changing the reactivated suspended well into a production well and changing it into an injection well. This effort is intended to obtain an optimum scenario for the water injection project. Specifically, the aim of this research is to utilize suspended wells to become production wells and injection wells as well as to overcome the problem of surface formation water waste with limited water treatment facilities.

Identification of Barriers and Productive Zones Using Reservoir Characterization

The most common complication faced by petroleum engineers is the description of a reservoir, both accurately and efficiently. Inadequate and insufficient reservoir characterization lead most enhanced oil recovery and secondary recovery projects to fail and also makes it difficult to deal with heterogonous reservoir. An accurate description of a reservoir is vital to the reservoir management and achieving maximum oil recovery. Reservoir characterization plays a very important role in descripting the storage and flow capacity of a reservoir and also plays a decisive role in reservoir simulation. The main objective of this research is to identify reservoir barriers and productive zone using reservoir characterization, in this study some of the most useful methods such as Flow Zone Indicator (FZI), Discrete Rock Type (DRT), Winland R35 methods were applied to 4 different wells to identify the rock types and flow units developing a static reservoir characterization model. To achieve the objective of this research the static model is transformed into a dynamic model by introducing graphical method such as stratigraphic flow profile (SFP), stratigraphic modified Lorenz plot (SMLP) and modified Lorenz plot (MLP) to easily quantify reservoir flow units based on physical structure, storage capacity, flow capacity, rock type and reservoir process speed. The physical structure permits the flow units to be interpreted in a stratigraphic model arrangement, determining well-to-well correlation schemes; the main aim of understanding the flow unit's characterizations is to identify the barriers, speed zones and baffles.

The Application of Water-flood Technology for Different Oil Fields

Water-flooding is perhaps the most common method of secondary recovery, in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells. In this study, three different fields from different locations were studied for a possible water-flooding operation using software. Through the results obtained from the application, certain predictions were obtained about the water-flood performance of the oil fields studied. It was concluded that the water-flood is a good solution as a secondary recovery project for the fields studied.

Increasing Sucker Rods' Working Capacities

Technology Update Artificial lifting systems are being pushed to their operational limits, given the more demanding field operating conditions that require deeper wells and higher production flows. Over the years, the number of secondary-recovery and nonconventional oil projects has increased, and more is being asked of rod pumping (RP) and progressive-cavity pumping (PCP) systems. Both pumping systems have found the sucker-rod string to be one of their weakest links. Stress analysis and failure statistics for different parts of sucker rods have found the weakest point to be located in its coupled connection. Rod-pin and coupling failures have become common problems in fields, making it clear that the fatigue resistance of the connection is inferior to the fatigue resistance of the rod body. Several potential solutions designed to increase rods’ working capacities have been attempted, but none of them attacked the problem genesis: the connection. Recently, however, a premium-connection rod has been developed with a new thread design that has demonstrated very positive results in reducing connection fatigue (Fig. 1). Design Process Finite element analysis (FEA) is a numerical tool used to verify designs before field testing can be performed, and with FEA, the most significant design constraints of conventional rod connections were analyzed as a basis for developing the new premium connection design. The main points addressed in the development of the new design were the following: Loosening tendency of the connection because of a gap between threads. This gap allows movement between coupling and pin threads when rods undergo compression and/or shocks. Permanent deformations of the thread (as verified by FEA) during makeup and well operations. These deformations make crack propagation more likely. They also result in a difficult makeup operation when repeating displacements. Nonuniform stress distribution in thread profile generates regions of high stress concentration and, as a result, makes the pin and coupling more susceptible to the appearance of cracks (also verified with FEA). High reliance on the makeup operation because both overtorque (increase in the stress level) and undertorque (stress concentration during well operation) are harmful for the connection and produce failures in sucker-rod pins and couplings. In conventional design, thread effectiveness is highly dependent on the cleaning operation before the string is run into the well and an inefficient makeup can easily result and later produce failures.

A New Method for Vertical Leak Detection in Low to Moderate Permeability Flooded Reservoirs

Summary Rising commodity prices have resulted in an increase in secondary recovery projects that are associated with lower permeability reservoirs. These processes often inject fluids above the parting pressure for the duration of the life of the flood, and pressurization takes place as fluids leak off from the exposed surface area of the induced fracture into the surrounding moderate or low-permeability reservoir matrix. The primary difference between these situations and conventional flooding is that matrix fluid migration is initiating off an induced fracturing plane, as opposed to point-source initiation. During the early history of a flood, mass-balance issues are often ignored, as average reservoir pressures are typically low, and injection rates can dramatically exceed production. As pressures rise, some localized portions of the reservoir not only can exceed virgin static pressures, but volumes near existing induced fractures can approach or equal the pressure in those fractures. When this occurs, vertical fracturing initiates within the reservoir, and can migrate either above or below the reservoir, depending upon the location of the closest lower stress interval. A new method to detect the location of vertical "leakage" has been developed. This method uses existing surface tiltmeter (STM) technologies and a new surface deformation calculation regime to zero in on volumetric changes that occur above or below the limits of the given reservoir. This method uses measured surface deformation from observed tilt to extrapolate the volumetric change at different specified depths. With a number of constraints and using a linear geophysical model based on poroelastic equations, an inversion routine is used to find the reservoir compaction or expansion at different depths. When volumetric change best fits the measured deformation data (or tilt) at the surface, the depth and aerial location is then correlated to the area near a specific well or wells.

Challenges for Waterflooding in a Deepwater Environment

Summary Big reservoirs in deepwater Gulf of Mexico (GOM) typically produce at world-class rates. The scale of investment is likewise world class. The energy industry's drive to invest in enhanced oil recovery from deepwater basins is sustainable in a world of volatile oil prices and increasing demand for energy. However, project economics will continue to depend on accurate risk assessment, risk-mitigation strategies, and, more fundamentally, progressive deployment of evolving technologies in brownfield deepwater secondary-recovery projects. Details of well geometry and design optimizations may prove to be minor sensitivities in high-cost deepwater developments; however, rig rate has a major impact on economics. The assessment required to minimize the number of injectors and ensure their proper placement logically takes more time than exotic choices of injection patterns. With such major constraints in mind, an optimal design for wells and materials has to take precedence. Accepting this as a given, additional, more common challenges would then follow. The waterflood-study team for the deepwater Ursa/Princess field in the GOM has spent appreciable time and effort evaluating various potential challenges affecting the surface and subsurface aspects of the development plan. The design for an optimum injection rate was a bottom-up process starting from the reservoir up to the topsides injection facilities. Reservoir-sweep efficiency and reservoir-pressure distribution logically dictated injection-well designs and injection-pump sizing. Subsurface risks, such as reservoir souring and hydrate formation, dictated materials selection and completions design. This paper addresses the challenges primarily affecting the design of the deepwater subsea-injection wells. In addition to the well cost, several other underlying factors have played an influential role in defining the boundary conditions for the injectors design.

Overview: Deepwater Exploration and Production (June 2007)

Offshore operators and contractors continue to accept and meet new deepwater challenges. As shown in the following articles, the apparent limits of deepwater technologies are extended every year, and new records and "firsts" are achieved to meet projects' increasingly ambitious requirements. Subjects covered this year include the first operational use of a new major equipment type, one of the first secondary-recovery projects in a deepwater environment, and two very different major deepwater projects. The projects and technologies described in the articles entail significant risks, and some of the articles discuss the risk management strategies used. The technical and commercial success of these projects depends on accurate risk assessment, risk mitigation strategies, and the continued progressive development of cutting-edge technologies. The use of new technologies, however, does not always result in increased risks. In some cases, technologies are devised to mitigate an identified risk, as indicated in the articles' discussions of "improved reliability," "enhancements in functionality," "optimization," "standard interfaces and interchangeability," "increased data quality," "improved durability," "improved facility uptime," and other key themes. Management of project risks is one of the most important tasks in project management. Rather than a one-off activity that is addressed only with a workshop facilitated by an outside expert and filed away, risk management should be an ongoing process that starts with project initiation and continues through the end of facility operation. Deepwater Exploration and Production additional reading available at the OTC Library: www.otcnet.org OTC 18768 "Polyester Mooring Lines on Platforms and MODUs in Deep Water," by John F. Flory, Tension Technology, et al. OTC 18493 "Extreme Wave Effects on Deepwater Floating Structures," by Bas Buchner, Maritime Research Institute Netherlands, et al. OTC 18797 "Combined Tow Method for Deepwater Pipeline and Riser Installation," by Alf Roger Hellestø, Subsea 7, et al. OTC 18844 "Special Session: AUVs: Groundtruthing High-Resolution AUV Side-Scan-Sonar Contacts for Unexploded Ordnance in a Deepwater GeoHazard Assessment," by Lynn B. Samuel, C&C Technologies, et al.

Aplication of the TDS technique for determining the average reservoir pressure for vertical wells in naturally fractured reservoirs

Average reservoir pressure is used for characterizing a reservoir, computing oil in place, performing reservoir monitoring by material balance, estimating productivity indexes and predicting future reservoir behavior and ultimate recovery. It is truly important to understand much reservoir behavior in any stage of the reservoir life: primary recovery, secondary recovery and pressure maintenance projects. The average reservoir pressure plays a critical role in field appraisal, well sizing, and surface facilities sizing. Almost every well intervention job requires the knowledge of this parameter. No significant research was conducted during the last three decades on the determination of the average reservoir pressure. The majority of the existing methods for determining average reservoir pressure are based on conventional analysis and some of them use correction plots for specific reservoir shapes which made them of low practicity. A new methodology based on the Tiab Direct Synthesis (TDS) technique uses the pressure derivative for determination of the average reservoir pressure was introduced very recently for vertical and horizontal wells in homogeneous reservoirs. This technique has been extended to naturally fractured formations using information from the second straight line of the semilog plot. By default, all reservoirs are naturally fractured; estimating the average reservoir pressure for homogeneous reservoirs should be a specific case of naturally fractured reservoirs. Currently, the inverse procedure is performed. Therefore, in this article a new, easy and practical methodology is presented for the first time, estimating average reservoir pressure for naturally fractured reservoirs (heterogeneous systems) during pseudosteady-state flow period for vertical wells located inside closed drainage regions. This technique employs a new analytical equation which uses a single pressure point and the value of the pressure derivative corresponding to the late time pseudosteady state period eliminating the use of correction charts and type-curve matching. We verified the proposed technique with simulated cases for values of the interporosity flow parameter, Λ, of 1 and the storativity coefficient, , of 0 (homogeneous reservoir) and successfully compared to traditional techniques and by the application to one field case. This technique (Tiab, 1995) is accurate since it uses an exact analytical solution and matches very well the results from conventional analysis. It is also more practical and much easier to use than conventional analysis.

Development and Field Experience of a New Concept in Sucker Rods Technology

Abstract The Cerro Drag?n oilfield, operated by Pan American Energy, has producing oil wells that use rod pumping systems with average depths of 2,440 m (8,000 ft) and fluid rates as high as 200 m3/d (1,300 bfpd). In this oilfield, the pulling operations exhibited a high incidence of pin breaks, generally located in the 22.23 mm (7/8 in) OD taper that we concluded to be the weakest part of the entire string, as we will show. In order to solve this problem, a new sucker rods design was developed by creating a new non- API 22.23 mm (7/8 in) sucker rod with ends of 25.4 mm (1 in) in order to reinforce the string. This technical work describes the development of this technology, as well as the experience in the field, with excellent results p to the present. Introduction erro Drag?n is an oilfield located in the Golfo San Jorge Basin (see Figure 1). This field has 1,800 oil producing wells, with 1,642 wells lifted by rod pumping systems. Average pump depths are 2,440 m (8,000 ft) with oil producing rates as high as 200 m3/d (1,300 bfpd). In 1988, a secondary recovery project was started. The water injection rate was raised (Figure 2), resulting in higher production rates and consequently higher loads to all of the components (rods, pumping units, etc.) of the lift system. Associated with this increase in the production rates, an increase in failure rates was observed. It was determined that the main cause of this failure rates increase was connection failures; in particular, the 22.23 mm (7/8 in) pin failures. Approximately 18% of the failures were caused by 22.23 mm (7/8 in) pin breaks. As a result, a team was established between the rod supplier and the operating company to work together to improve the fatigue resistance of the 22.23 mm (7/8 in) connection. The result of this teamwork was a new non-API sucker rod with a 22.23 mm (7/8 in) diameter and a threaded connection of 25.4 mm (1 in). Currently, there are 60 rod strings installed, the oldest ones with an operating service life of about four years, and there has been just one failure (the oldest one failed after 1,499 days in service). The installation of the improved sucker rods in 160 wells (thosewith the higher failure rates) will result in savings of almost US$2 MM/year. This paper describes the development of the rods, as well as the experience in the field. Failures History Due to the increase in the IPA (index of interventions per well per year) for wells lifted by rod pumping (Figure 3), work was conducted to understand the different causes of the failures. The first conclusion was that the sucker rod failures were growing at a constant rate, corresponding to the increment in the production rates.

Formation Damage Control: Selecting Optimum Salinity in a Waterflooding Pilot

Abstract Waterflooding in viscous oilfields poses several problems to both the reservoir engineer and the production engineer. Despite unfavourable mobility ratios, it has been noted that injection performance often exceeds theoretically expected values. In the particular case of the waterflooding pilot project across the Cerro Fortunoso field (Malargue, Argentina), the occurrence of several water supplies of widely varying salinity coupled with the usual problems. This paper describes a pilot study designed to determine the optimal salinity of water to be injected, in order to avoid formation damage resulting from clay deflocculation through what is known in the literature as saline shock. As is clearly shown by the results of the study, abrupt changes in the salinity of injected water result in significant decreases in permeability. According to the study, the problem is minimized over certain ranges. Introduction The Cerro Fortunoso field is located in southern Mendoza, Argentina, in an environmental reservation area known as La Payunia, 135 km away from the capital city of Malargue Department (Figure 1). The field is characterized by its complex structure, which consists of a NNE-SSW striking narrow, elongated, and faulted anticline. Four major east dipping, NNE striking thrust faults are predominant. The oil bearing region belongs to the Neuquen Group, and develops along the anticline flanks. A gas cap, consisting mainly of CO2 (85 to 95% molar content), occurs in the upper part of the structure. Geologically, the field involves fluvial deposits exhibiting considerably marked tectonics with high dips (40 ° to 70 °) and intense NE-SW faulting, giving rise to compartmentalized lenticular reservoirs of poor areal continuity. These lenses are sand/shale intercalations with an average porosity in the order of 18% and mean permeability in the 50 mD range. Background There was concern about the feasibility of a secondary recovery project in the Cerro Fortunoso field, which contains a predominantly asphaltene-based, very viscous heavy oil (14 ° API). Complete information regarding the field's main features and its fluids can be found elsewhere(1). Numerical simulation of the reservoir characterization study performed in Canada with Teknica Overseas Ltd. made comple completion of the project feasible(2). The study warned about the potential negative effects of fresh water injection, due to the occurrence of smectite, illite and kaolinite. At an early stage, the most suitable area for implementation of a pilot project was studied and steps were taken to identify for potential water sources. Thus, we faced one of the main difficulties to overcome. As was described above, the field is located in an extremely desertlike environmental protection area where the nearest river (Rio Grande) is 70 km away. No lacustrine deposits or natural springs occur in the area. Water Sources The use of battery-gathered production water was initially ruled out due to low production rates, high emulsion content, and the significant treatment cost that it would require. The use of two additional water sources was also discussed, i.e., production water separated in the Los Cavaos field and production water from a nearby field which is operated by third parties.

ABSTRACT: A Method for Predicting Sand Thickness from 3-D Seismic, Upper Jurassic Frisco City Sand, Monroe County, Alabama

Abstract As exploration for Upper Jurassic Haynesville Formation reservoirs in southwest Alabama enters a mature phase and continues into a second decade, new predictive techniques are needed to expand the play beyond the current producing areas. In addition, new methodologies will play a key role in the successful implementation of secondary recovery projects in the existing fields of this prolific oil trend. A critical element in the exploration and development of Haynesville objectives is predicting reservoir thickness. Within this trend, Haynesville sandstones demonstrate variable thickness. This is a result of a range of depositional morphologies within the context of regional tectonics. An integrated 3D seismic and subsurface evaluation of three fields productive from the Frisco City Sand member of the Haynesville Formation in Monroe County, Alabama resulted in the development of a methodology to accurately determine the thickness variations of this reservoir. In concert with knowledge of depositional patterns and local structure, this quantitative technique can be carried beyond the fields studied and used regionally as an exploration tool, as well as locally in aiding exploitation and enhanced recovery projects in existent Haynesville fields.

Oil Recovery From Tarmat Reservoirs Using Hot Water And Solvent Flooding

Abstract The existence of tar accumulations (tarmat) beneath the oil zone in some reservoirs creates productivity problems through restricted aquifer support during the primary recovery stage. It also affects the performance of peripheral water injection when the tar/oil boundary is irregular. The objective of this study was to investigate and evaluate combined solvent and hot water injection beneath the tarmat to improve aquifer support by displacing and dispersing the tar. Displacement runs were conducted in one-foot long Berea sandstone composite cores, simulating a tar zone and an oil zone in series, at injection rates of 1 ml/min. and higher. The results show that although the oil recovery from hot water displacement is lower than cold water displacement in the absence of tar, the gain in recovery for hot water over cold water is substantial in the presence of tarmat. Driving a slug of solvent with hot water to displace tar increases the hydrocarbon recovery even further. However, for each of the two solvents studied, there is an optimum slug size with which the hydrocarbon recovery is maximum. Moreover, the recovery was found to increase further when the optimal slug is divided into portions separated by small slugs of hot water. The injection rate had a profound effect on the recovery for all hot-water flooding schemes. The results showed consistently that the recovery increased at lower injection rates. Introduction Many oil reservoirs are characterized by the presence of a highly viscous hydrocarbon layer (tarmat) at the oil/water contact. Such tarmats are found in many major oil reservoirs in the world and, particularly, in the Middle East. They are reported in the literature to vary widely, ranging from highly viscous hydrocarbon fluids to near solid materials(1). The thickness of the tarmat varies from place to place in the same reservoir and sometimes reaches few hundred feet; while their extent can reach several kilometres. In Ghawar field, for example, the tar zone extends more than 25 km and reaches up to 150 m in thickness(2). Several geochemical studies presented by various authors attribute tarmat formation to gravity segregation which leads to a compositional grading with depth(3–5). Depending on reservoir conditions and tar viscosity, field experience shows that some of these tarmats can become mobile under conditions of moderate differential pressure(2). The presence of tar deposits at the oil/water contact in a tarmat reservoir can have serious adverse effects on the effectiveness of natural water drive as well as secondary recovery projects. When the tarmat completely surrounds the oil zone, the oil reservoir behaves like a finite lens where the pressure decreases rapidly as soon as the first well starts producing. This leads to an alarming increase in gas/oil ratio during the primary stage of depletion which has been the case with Minagish reservoir in Kuwait(2). Another such example is El Bundug reservoir in Qatar(6).

New logging tool identifies permeability in shaley sands

A logging tool overcame questionable results obtained by routine core analysis and other conventional techniques for identifying permeable zones. For this test, Lomax Exploration Co., in conjunction with the US Department of Energy (DOE), used Numar corp.'s magnetic resonance imaging log (MRIL) in the Monument Butte field, Duchesne County, Utah. The tool also enhanced the interpretation of conventional logs over the two zones of interest. Because of interbedded sands, shales, and silts, cores collected just inches apart can yield very different permeability and porosity values. As a result, sidewall core analysis has historically been misleading. Lomax Exploration felt that MRIL could improve permeability determinations for secondary recovery projects as well as aid in evaluating zones for initial production in the Uinta basin. The paper describes the Uinta basin, MRIL, MRIL logs, and well completion.

Two-Step Rate Test: New Procedure for Determining Formation Parting Pressure

Summary. A reliable estimate of the formation parting or fracture extension pressure is important for efficient operation of waterfloods and tertiary recovery projects. A new procedure, called a two-step rate test procedure, called a two-step rate test (2-SRT), is presented for determining this pressure. Unlike a conventional step rate test (SRT), which consists of several constant-rate injection steps, the 2-SRT requires only two injection steps, during which pressures are measured continuously. Test procedure, design and analysis procedure, design and analysis considerations, and recommendations for test implementation are provided. Field examples are included. The 2-SRT procedure offers potential for time procedure offers potential for time and cost savings over a conventional SRT. Introduction Rapid water breakthrough in production wells as a direct result of exceeding a certain critical injection pressure in nearby injection wells was observed as early as 1945. This critical injection pressure is called the formation or fracture parting pressure (FPP). The FPP is equivalent to the "fracture extension/propagation pressure" in the hydraulic fracturing literature. Several studies recently demonstrated that a fracture will continue to propagate if injection is above the FPP and the injection/ withdrawal ratio is greater than one. In addition to this uncontrolled fracture extension, injection above the FPP may also cause fracturing out of pay. These factors may lead to premature breakthrough of injected fluids, poor sweep efficiency, reduced recovery, poor sweep efficiency, reduced recovery, and loss of costly injection fluids. On the other hand, injection far below the FPP may result in injection volumes much lower than the allowable maximum and a reduced rate of oil recovery. A reliable estimate of the FPP is therefore critical in conducting secondary and tertiary recovery projects. The SRT has been the primary method used for several years to determine FPP. A recent paper provided a detailed discussion of the design and analysis of SRT'S. To define the FPP adequately from an SRT, several (usually seven or more) constant-rate injection steps, generally of equal duration, are needed. Further, the duration of each step (also referred to as timestep size) should ideally be long enough for the data to be free of wellbore-storage effects. If continuous pressure measurements are available during pressure measurements are available during an SRT, the data can be analyzed by multiple-rate superposition methods to determine the FPP. The Odeh and Jones superposition method or Agarwal's multirate equivalent time analysis can be used to analyze SRT data. Ref. 7 gives a detailed discussion of the proper application of multiple-rate analysis and identification of FPP from such an analysis. This paper describes a new test procedure (2-SRT) for determining FPP. The 2-SRT requires only two constant-rate steps, during which pressure and time data are measured continuously and analyzed for determination of the FPP by multiple-rate superposition methods. Pressure data from the two steps are compared on Agarwal's multiple-rate equivalent-time basis. Guidelines for the design and analysis of a 2-SRT and recommendations regarding the test implementation are provided. Field examples are included to demonstrate the applicability of this procedure. procedure. Discussion Test Procedure. The 2-SRT can be run in at least four different modes shown schematically in Fig. 1. For each mode, the test well is either shut in or stabilized at a constant injection rate before the start of the test. In either case, the stabilized pressure before the 2-SRT must be below the FPP. Modes 1 through 3 refer to cases where the well is stabilized at a constant injection rate before the test is run. Mode 4 is the case when the well is shut in at the time of the test. The 2-SRT procedure for each mode is described below. Mode 1. The injection well is shut in for Step 1, followed by injection at a high constant rate for Step 2. The injection rate for Step 2 is chosen such that the FPP will be exceeded. Mode 2. If the well is on a stabilized low-rate injection, Step 1 of the test may be stepping up the injection rate to a constant value that is still low enough so that the FPP is not exceeded. The injection rate is then further increased to a higher constant rate for Step 2. Mode 3. The injection is reduced to a lower constant rate for Step 1 and then increased to a higher constant rate for Step 2. Mode 4. The well is stabilized at shut-in conditions. The 2-SRT consists of two constant-rate injection steps with a stepwise increase in the injection rate for each step. For all the modes of the 2-SRT procedure, it is extremely important that the pressures attained for the entire duration of Step 1 are below the FPP. The injection rate for Step 2 is chosen such that the injection pressure will exceed the FPP during this step. JPT P. 84

Variational principles and finite element method for stress analysis of porous media

AbstractA number of variational principles are established in this paper for the stress analysis of porous media with compressible constituents. A three‐dimensional finite element method is proposed based on the variational principle. The finite element method thus established is applied to the study of the temperature, deformation and flow field associated with the water‐flood technique in secondary recovery projects for oil exploration. In the study model, the layout of injection wells and production wells is considered to have a regular pattern where symmetry conditions exist. The injection fluid diffuses slowly into the formation through a vertical crack which is initially generated by an explosion. The problem is analysed by a plane strain formulation with the effects of heat conduction and convection included.

World stress map: International workshop on the European contribution

Ever since the recognition of plate tectonics as a major Earth process, maps of the orientation of stress in Earth's crust have given us one of the most direct clues to the forces that drive plate movements. We now know from these maps that stress orientations are consistent on a regional scale, that the boundaries between provinces of uniform stress direction generally coincide with major physiographic and structural boundaries, and that for many regions the orientation of the maximum compressive horizontal stress generally coincides with directions of plate motion [e.g., Zoback and Zoback, 1989].On a regional scale, maps of crustal stress have provided striking evidence of the low strength of plate margin at the San Andreas Fault in California [M. D. Zoback et al, 1988]. In industry, maps of stress orientations have been used to plan secondary recovery projects for oil and gas [Bell and Babcock, 1986] and evaluate seismic risk near critical facilities [e.g., Stock et al., 1985].

Integrated Air Separation Facilities For Hydrocarbon And Sulphur Recovery

Abstract The concept of using an air separation plant to generate nitrogen jar enhanced hydrocarbon recovery and oxygen for sulphur production is reviewed. Nitrogen generation (for injection) and nitrogen rejection processes are discussed and cost curves are presented. Conventional oxygen enrichment and the COPE ™ (Claus Oxygen-based Process Expansion) sulphur recovery processes are compared. Locations where an air separation facility can be designed to produce both nitrogen jar injection and oxygen jar sulphur recovery are identified. Having identified potential sites for integration, oxygen and nitrogen economics are presented. Introduction North America contains vast reserves of conventional crude oil, heavy oil, oil sands, and natural gas containing sulphur (as hydrogen sulphide). In order to produce these reserves economically, industry is constantly investigating the application of new methods to enhance production. Some of these methods use industrial gases such as nitrogen (in secondary and tertiary hydrocarbon recovery projects) and oxygen (in situ combustion for heavy oil recovery and to displace air in sulphur recovery units). These gases are co-produced in cryogenic air separation facilities. However, to date, the application of air separation technology has been very site/project specific and designed to recover only one industrial gas. Many air separation facilities have been installed to deliver nitrogen for enhanced hydrocarbon recovery (EHR). At these locations the low-purity oxygen by-product is vented to the atmosphere even though it could be used as an efficient source of oxygen for combustion processes, such as sulphur recovery from a Claus unit. Hydrocarbon Recovery- Nitrogen Injection/Rejection The use of cryogenically produced nitrogen from an air separation unit (ASU) was initiated in the late seventies as a cost-effective alternative to natural gas injection(I.2). Its use for EHR has grown dramatically and has been applied primarily in the "lower 48" United States. In their June 1985 paper, Clancy et al.(2) provide a list of 33 reservoirs which have used nitrogen injection technology. Figure 1 locates the sites (illustrated by triangles) from this list which have used cryogenic air separation facilities to produce nitrogen. Sites where a nitrogen rejection unit (NRU) is installed as well are located by a darkened triangle in Figure 1. One of the eight sites where both nitrogen injection and rejection and are practiced is Dome's Willesden Green Field in Alberta(4). Exxon operates an integrated injection/ rejection project at Jay-Little Escambia Creek Field near the Florida/Alabama border(5). The remaining six sites are located at University Block 31 (Texas), Anschutz Ranch East Field (Wyoming), Andector-Ellenberger Field (Oklahoma), Fordoche Field (Louisiana), and two at the Painter Field (one triangle shown in Wyoming). Sulphur Recovery The primary method of producing elemental sulphur from natural gas is with the use of the Claus process. A typical modified Claus sulphur recovery unit (SRU) with two catalytic conversion stages and a modem reheat scheme uses air as the course of oxygen to recover 93% to 96% of the sulphur from a relativelyrich acid gas feed.

Oil Production Response To In Situ Electrical Resistance Heating (Erh)

Abstract An oil well can be stimulated by applying AC current to the formation in a single well. This type of stimulation can be called electrical resistance heating (ERH). The viscosity reduction which results from a higher temperature around the wellbore increases the oil production rate. This process has been tested in the field and the performance successfully matched with reservoir simulation. This study was performed to find a simple method of estimating steady state stimulated production rate. A two-dimensional simulator was developed and run for 52 cases which covered a variety of reservoir conditions. This sensitivity analysis showed that four parameters accounted for most of the variation in production rate. The parameters were initial oil viscosity, formation thickness, drainage radius and induced temperature change. The predictive equation takes the form of steady-state radial Darcy's Law with a modified oil viscosity term. The modified oil viscosity is a weighted average between the initial oil viscosity and the minimum oil viscosity at the wellbore. The weighting factor was matched to the reservoir simulation results by regression analysis. The use of this simple predictive equation agrees well with simulation results for steady state flow. Introduction Oil production can be stimulated by applying electrical power in the formation. The electrical power causes a temperature increase which reduces oil viscosity and results in increased oil production rates. Electrical energy is converted to heat in the formation by a combination of electrical resistance heating (ERR) and electromagnetic power absorption, depending on the electromagnetic power frequency. This study was- confirmed to electrical resistance heating (ERH), which is the major source of heating when low frequency (60 Hertz) AC electric power is used. The literature reveals several papers dealing with the possibility of using the ERR process for stimulating oil recovery.(1,5). Pilot studies have also been initiated in Canada, United States, Mexico, and other countries with varying degrees of Success(1,3,6,7). One of the earliest examples of electrically stimulating oil recovery was reported by World Oil in 1970(1). The method was designated as the "Electrothermic Heating Process". The process used an AC current applied around the wellbore. The heat was reported to improve production of low API gravity oils up to 300%. Single-phase AC electric power was used to avoid metal corrosion associated with DC electric power. Flock and Tharin(2) mentioned multi-well ERH as a possible recovery method. They proposed using electrically heated water in secondary recovery projects to increase displacement efficiency. They also pointed out poor efficiency in electric power generation was a major drawback to the ERH method. As a result, Flock and Tharin considered ERR as a preheat for more conventional thermal processes rather than an independent recovery process. Schumacher(3) reported on ERR using multi-well installations. Because of the high cost of electrical power it was primarily considered as a means of preheating a reservoir as noted in the Flock and Tharin paper. The problem of water flashing to steam near the wellbore was also noted.

Development Geology of 20% of Total United States Daily Production on Alaska's North Slope: A Technical and Management Challenge: ABSTRACT

The giant fields on the North Slope of Alaska combined (Permian-Triassic/Lisburne pools at Prudhoe Bay and the Kuparuk field) produce approximation 2 million BOPD and contain about 30 billion barrels of oil in place. Because the reservoirs in these fields are complex and the stakes in efficient field management so high, the development geology of these fields presents a great challenge. The technical challenge lies in the fact that the full areal extent and heterogeneity of the producing reservoirs are not yet known. Secondary and tertiary recovery projects have been initiated very early in the lives of these fields to ensure maximum recovery. Thus, the development geologist has to locate drill sites in support of primary development drilling while at the same time formulating a reservoir description from an incompletely drilled field. In support of waterflood and EOR projects, detailed structural work is being carried out and permeability barriers and pathways are being identified and mapped. The management challenge is in keeping communications channels open between the development geoscience group and the reservoir, production, operations, and drilling engineers. The development geologists must communicate in engineering language not only to be able to understand the problems described by engineers but alsomore » to be able to explain geologic concerns and solutions. Therefore, the geologic work has been carried at two levels. At the basic scientific level, interpretations of depositional environments, regional setting, facies distribution and diagenetic and porosity trends are being carried out. At the applied level, this knowledge is integrated with engineering practice.« less

Development Geology of Giant Fields on Alaskan North Slope: Key to Successful Reservoir Management: ABSTRACT

The giant fields on the North Slope of Alaska (combined Permian-Triassic/Lisburne pools at Prudhoe Bay and the Kuparuk River field) produce approximately 2 million BOPD and contain about 30 billion bbl of oil in place. This production rate amounts to almost one-fourth of the United States daily production. Because the reservoirs in these fields are complex and the stakes in efficient field management so high, the development geology of these fields presents a great challenge. The technical challenge of managing these fields lies in the fact that secondary and tertiary recovery projects have been initiated soon after start-up to ensure maximum recovery. Thus, the development geologist has to recommend primary development locations while formulating a reservoir description without knowing the full areal extent and heterogeneity of the reservoirs. To support the waterflood and enhanced oil recovery projects, permeability pathways and barriers have been identified using sedimentological, log, and engineering data. Because structure also plays an important role in controlling fluid pathways, the fault geometries, fracture patterns, and detailed structure are being mapped using two-dimensional and three-dimensional seismic, well, and log data. The management challenge of development work in these fields is keeping communications channels open among the development geoscience group and the reservoir, production, operations, and drilling engineers. The development geologists must communicate in engineering language not only to be able to understand the problems engineers End_Page 1521------------------------------ face but also to be able to explain geologic concerns and solutions in terms understandable to engineers. Therefore, the geologic work in these fields is conducted at two levels. At the basic scientific level, interpretations of regional settings, depositional environments, facies distribution, and diagenetic and porosity trends are being carried out. At the applied level, this knowledge is integrated with engineering plans and modeling studies for projects such as delineation and infill drilling, well completions, waterflood, and enhanced oil recovery. End_of_Article - Last_Page 1522------------