Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract This paper investigates the effect of higher concentrations (0โ100%) of CO2, H2S, and N2 on natural gas well deliverability, reserve estimation, and pressure test analysis quantitatively. Physical properties of natural gases such as viscosity and compressibility are corrected according to the concentrations of the contaminant gases such as CO2, N2, and H2S present in it. These contaminant gases have profound impact on pressure test analysis. The Carr et al viscosity correction chart allows adjusting the viscosity up to 15% concentration of these contaminant gases. However, Wichert and Aziz compressibility correction chart allows up to 80% concentration of the CO2 and H2S. Tiab developed an analytical method to estimate pseudopressure function for 0โ100% combined-concentration of CO2, H2S, and N2. His pseudopressure was first re-plotted to simplify the procedure and then it was used to analyze the deliverability, pressure tests, and decline curves quantitatively. The analysis was performed with Carr et al viscosity correction chart, pure CO2 properties, and then with Tiab's corrected pseudopressure. Pure CO2 properties were used due to the fact that the sample data has 98.256% CO2. During this study it was observed that the compressibility factor has a little effect on analysis since it is a volume-related property. Viscosity, however, has the largest effect on the analysis since pressure is transmitted through the fluid in the porous media and viscosity works against it. It was also observed that the numerical method of calculating pseudopressure function introduced successive error in the analysis. Number of pressure data points also contributed to theerrorinnumericalintegrationofthepseudo-pressure function. Analysis of field as well as simulated examples resulted an absolute error range of 13โ75% in the permeability estimation in pressure tests, 77% in deliverability tests, and 20โ95% with pressure derivative. Error in AOF was observed as 15% and as high as 32 % in reserve estimation. Introduction The High energy (Temperature and Pressure) environment and the presence of Oxygen rich compound turned many of the hydrocarbon reservoirs into CO2 rich reservoirs. Such reservoirs usually are of low commercial value due to higher concentration of sour gases. Fig.1 shows the existence of CO2 rich reservoirs in United States. Texas, New Mexico, Colorado, Mississippi, Wyoming, and Utah are the states with abundance of this natural resource. Two major consumers of CO2 are the Chemical and Petroleum industries. Due to its miscibility in both water and oil, CO2 has found its niche in EOR operations of miscible flooding. However, the potential for CO2 flooding and its other application will be significant if it is found in enough quantity. Thus, its use and production as a natural resource requires the development of engineering techniques to analyze such reservoirs effectively.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract San Andres carbonate reservoirs have long been known to have a high degree of reservoir heterogeneity and poor recovery efficiencies. Fractures are one of several causes of this heterogeneity. The heterogeneity causes unpredictability in water and CO2 flooding. However, the correct placement of horizontal wells can take advantage of this problem. An integrated reservoir characterization study of the Mabee field incorporating oriented core, Formation Microscanner (FMS) wireline logs, seismic time slices, production character, curvature analysis, and interference testing was used to predict fracture orientation and areas of highest fracture density. These fracture characteristics were then applied to determine horizontal well loca-tion and orientation. Fracture orientation was evaluated through the analysis of oriented core, FMS logs, and interference testing, indicating a fracture orientation of N70W. Analysis of the induced fractures in the oriented core indicates that the direction of maxi-mum horizontal compressive stress is N45E. High fracture density was delineated by curvature analysis, relative seismic amplitude, and areas of higher production. Areas with high curvature corre-spond to areas of high relative seismic amplitude and higher production. The data integration indicates that four areas have high fracture density. The synthesis of fracture orientation and density, along with the production character, indicates the optimal location and orientation of horizontal wells. Introduction Low-permeability San Andres reservoirs of the Central Basin Platform contain significant volumes of remaining oil. The Mabee San Andres field lies on the northeastern edge of the Central Basin Platform (Fig. 1) and is part of the San Andres/Grayburg Platform Carbonate play. Ref. 1 reported recovery efficiencies for secondary recovery of approximately 30% and an unrecovered resource of 2.6 billion stock-tank barrels of oil. The low recovery efficiency and still-remaining resource are due largely to the signif-icant amount of heterogeneity found in these reservoirs. San Andres Platform Carbonate reservoirs are highly hetero-geneous because of the depositional facies, diagenesis, and frac-turing. Ref. 2 described how grainstone bar depositional facies significantly affected the production character in Dune (Grayburg) reservoirs. Ref. 3 described how areas of postdepositional dia-genesis were the most highly productive in the Jordan (San Andres) reservoir. Additionally, fractures have been cited as contributing significant heterogeneity to San Andres/Grayburg reservoirs. Ref. 4 sited fractures in the Arrowhead (Grayburg) reservoir as the reason that tracers broke through in 2 days between a five-spot well pat-tern. Ref. 5 described the influence of fractures in the Keystone East (San Andres) reservoir. Ref. 6 described how fractures in the Chaveroo and Cato (San Andres) reservoirs influenced flow and storage volume. Ref. 7 depicted natural fractures as dominating the permeability character in zones of the Levelland (San Andres) reservoir. This heterogeneity causes preferential fluid flow and often-early breakthrough in waterfloods. It is also the likely cause of water loss previously unaccounted for in San Andres waterflood operations. Ref. 5 described a northeast preferential flow direction coincident with their interpreted direction of maximum horizontal compressive stress. Ref. 8 cited the Fullerton Clear Fork, Keystone Colby, and Means (San Andres/Grayburg) reservoirs as having east-west preferential flow directions. It is reasonable that this similar preferential flow direction in several fields and several formations is due to open fractures. Both the direction of open fractures and the location of densely spaced fractures influence how fractures affect production. In this study we combine geologic and engineering information including interference tests, oriented core, Formation Microscanner (FMS) logs, production data and curvature analysis to evaluate the direc-tion of open fractures and the areas where they may be more densely spaced.
- North America > United States > Texas > Andrews County (0.36)
- North America > United States > Texas > Crane County (0.28)
- North America > United States > New Mexico > Lea County (0.28)
- North America > United States > Texas > Travis County > Austin (0.15)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (42 more...)
Abstract This study investigates the effect of horizontal wellbore hydraulics on the early time dynamic behavior of horizontal wells. A finite conductivity model has been developed to couple infinite-conductivity horizontal well model based on uniform flux solution and finite conductivity wellbore hydraulic model. A sensitivity study is presented to show:The effect of horizontal well conductivity on production distribution along the wellbore at different time-steps, including early time radial flow, intermediate time linear flow and late time radial flow. The effect of wellbore length on the magnitude of wellbore-pressure drop under different values of Horizontal Well Conductivity, CHD, and Reynolds number, NRe. The effect of pipe roughness, Rp. The effect Reynolds number at the downstream end of the well, NRe. The new finite conductivity model is evaluated by setting a computer programs using Mathlab programming. The programs can include any friction factor correlation and production scheme. Type curves, of dimensionless pressure and pressure derivative versus dimensionless time, are obtained for different values of horizontal well conductivity and Reynolds number. These sets of curve can be used for type curve matching techniques. Correlations of the additional pressure drop due to finite conductivity solution over infinite conductivity solution, ?PD(tD), are presented for different values of dimensionless well length, LD, horizontal well dimensionless conductivity, CHD, Reynolds number, Re, and pipe roughness, Rp. Introduction The magnitude of wellbore pressure drop has been considered negligibly small in order to satisfy the infinite conductivity and uniform flux idealization. However in some circumstances the pressure drop in the horizontal wellbore can have an effect on the horizontal well behavior. This is supported by the numerous studies incorporating the effect of pressure drop in horizontal well models. In practice, some pressure drop from the tip of a horizontal well to the producing end is needed to maintain fluid flow within the wellbore. As a result, the downstream end of the horizontal well will be subjected to a lower pressure than the upstream end. Hence, for better understanding of horizontal well behavior, a good estimate of the pressure drop within the horizontal portion of the well is needed. This estimation can help reservoir engineers in optimizing an individual completion and/or optimizing the depletion plan for a reservoir. The major reason for drilling a horizontal well is to produce with a higher flow rate at a lower reservoir pressure drawdown. Frictional pressure losses could be comparable to the pressure drop within the reservoir. In such a case, drilling a longer horizontal well may not enhance the productivity. In this study, a semi-analytical model is developed and a sensitivity study is performed on the parameters affecting finite conductivity pressure solution. Literature Review The intensive theoretical studies of horizontal wells over the last two decades have shown that the incorporation of horizontal wellbore hydraulics into the horizontal well model is a challenging issue. This section will review the relevant literature concerning the effect of hydraulics on horizontal well performance. Dikken was the first to incorporate the effect of frictional wellbore pressure drop in horizontal well productivity. His basic assumption is that the productivity index per unit length of horizontal well is constant. He developed a second order differential equation to determine the wellbore flow rate at any location in the wellbore. He then solved analytically the differential equation for the case of infinite wellbore length and numerically for the actual case. Novy extended Dikkin's work to gas wells. Landman and Halvorson presented analytical solution to the non-linear differential equation. However, both of their solutions were limited to special cases.
- North America > United States > Texas (0.67)
- Africa > Middle East > Algeria (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Abstract In heterogeneous reservoirs like Hassi Messaoud, the exact interwell location of each reservoir sandstone body can not be in most cases easily located, and the potential of drilling unsuccessful production wells is usually present. In this situation a reservoir characterization model with usable uncertainties is needed. Conventional modeling techniques fail to quantify heterogeneities in lateral direction, however horiontal well data appear to compensate for this lack of information, providing some knowledge about variability of reservoir parameters, using data recorded along the horizontal drainhole of horizontal wells, hence providing adequate measurements of reservoir properties in the interwell locations. In this study a petrophysical model was generated for the north east area of Hassi Messaoud field comprising four horizontal wells. The generated models of porosity permeability and shale distribution were in agreement with Hassi Messaoud braided fluvial depositional model. The facies lateral variations have confirmed the nonuniform depletion throughout this sector of the field, which has led to its zonation. Once the reservoir characterization was complete, the generated model was validated using a full-field model of North East area, that involves history match of each well individually. Introduction For each target reservoir, many geostatistical realizations can be generated by integrating seismic, sedimentology, geology, and petrophisical data with their respective uncertainties captured by these models. Traditionally, reservoir description has been interpolated at the inter well locations, using simple algorithms, which fails to capture the true geological complexity and therefore results in ineffective prediction. To address this failure in the traditional route, one needs to consider using tools which allow the user to represent more accurately the range of plausible geological cases. Stochastic modeling techniques are used to construct detailed geological description using structural information, diagenetic and depositional models, reservoir stratigraphy, log and core data, and fault and fracture information. In most cases, adequate measurements of reservoir properties are not available to evaluate inter well variability at small scales. Information about lateral variations of reservoir parameters comes from horizontal wells or seismic data. Log data from horizontal wells have been used to improve inter well reservoir characterization, identify fractures and lateral variation of facies. Stochastic reservoir modeling is becoming commonly used tool to describe reservoir heterogeneities. It involves the generation of images of the reservoir lithofacies and rock properties that ideally, would honor all available data (Core measurements, well logs, seismic and geological interpretations, analog outcrops, well test interpretations, etc). Certain information, like production data or effective properties derived from well tests, can not be easily incorporated into the reservoir model. Almost always, a stochastic reservoir modeling exercise will involve a hybrid technique combining the best features of a number of available algorithms. Simulated annealing is an algorithm initially developed for the solution of combinatoin optimization problems. Generally, conventional modeling techniques fail to capture the true geological complexity of the reservoir in the lateral direction due to the lack of data in unsampled zones. In most field cases, only vertical well data representing a small fraction of the reservoir are available to describe the spatial distribution of reservoir properties. Horizontal wells, however, have emerged to quantify heterogeneities in the lateral direction because of their extended reach.
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud (0.99)
- North America > United States > Texas (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.89)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.68)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.73)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (25 more...)
Abstract Many oilfield service companies as well as oil producers have manually tracked assets over the years for a variety of reasons. The service companies have tracked assets such as pumps, packers, or other products to assist in R&D efforts. Being able to collect the data and compile statistics on run times and component failures enables the service companies to evolve and improve current products as well as design new products. From a producers perspective, compiling the same or similar data allows for the development of "best practices" in operating procedures and processes. Software products developed to address these needs have evolved with time to provide more functionality. However, many systems implemented to handle the total process of data acquisition, warehousing, querying, and reporting to achieve improved operating results have become more difficult and expensive to support than the value added. The value of the information has not diminished, but increased due to the fluctuations in oil prices and the continuing efforts to reduce lifting costs through design and process enhancements. The recent development of a web based tracking system incorporates workover management, downhole equipment, and chemical usage while enabling the operator and service provider the ability to easily enter and access the data. The system reduces the problems of database synchronization, multiple entries of the same data, and provides a common means through the Internet to interface with the information. The system links the operator in the field, the service company providing equipment or chemicals, and the district office together through a common database that each has access to. The system allows a technician in a pump shop, workover foreman in the field, or chemical sales person to easily enter data into the system using a laptop computer or touch screen technology. The data is brought back to the service provider's local office and is accessible to the operator through the Internet. Wells, well equipment, and equipment components can be tracked for run life and root cause of failure. The operation becomes an information network that uses the same data to accomplish different tasks but with a common objective of reduced costs and improved profitability. Introduction Service Providers. In the oilfield service sector, the larger service companies began internally tracking their own equipment failures many years ago. Until recently, the service industry's perspective on failure analysis has been much different than that of the producer. By evaluating and categorizing failures, new products can be designed to fill niches or actions can be taken to improve the product over the competition. If a service provider did not have a process improvement cycle in place or a way to continuously improve the current line of products offered, they could fail both competitively and financially. Over the years, manual tracking and reporting systems were put in place that involved the field service technician, equipment maintenance personnel at the warehouse, warehouse clerk, and local technical engineer or manager (Figure 1). Because of all the "handling" of data from the time a failure occurs until the root cause is determined, the probability of incorrect data resulting from human error becomes extremely high. Each person in the process could potentially enter bad or erroneous data into the system, thereby nullifying or reducing the value in the desired result. In addition, the lag time between the failure occurrence and the reporting cycle producing client reports is generally a month or more. If mistakes are made during this process and are discovered in the reports a month later, some data may be lost forever. Only by acquiring large amounts of data, and having a conscientious attention to detail by all persons involved in the process, can the statistical probability for correct interpretation of the data become more accurate.
- North America > United States > Texas (0.68)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Production and Well Operations (1.00)
- Health, Safety, Environment & Sustainability > HSSE & Social Responsibility Management > Contingency planning and emergency response (0.55)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (0.48)
- Management > Professionalism, Training, and Education > Communities of practice (0.34)
- Information Technology > Communications (1.00)
- Information Technology > Human Computer Interaction > Interfaces (0.88)
- Information Technology > Data Science > Data Quality (0.86)
Abstract South Wasson Clear Fork field produces from two reservoirs, the middle Clear Fork, with a seal located within the upper Clear Fork Formation, and the lower Clear Fork, with a seal located in the Tubb Formation. Six sequences have been defined on the basis of facies succession, seismic interpretation, and outcrop analog studies in Apache Canyon, Sierra Diablo Mountains, West Texas. Rock-fabric/petrophysical studies have shown that a single porosity-permeability transform and porosity-saturation-capillary- pressure model can be used to calculate permeability and water saturation in uncored wells. Five rock fabrics have been described, and all plot in the petrophysical class 1 field. This surprising result is related to the presence of large volumes of poikilotopic anhydrite, which reduces porosity but has little effect on pore size or perme-ability. Permeability values calculated from porosity logs are distributed in the interwell environment within a high-frequency-cycle (HFC) stratigraphic framework. Analog outcrop studies demonstrate that the Clear Fork Formation can be characterized by upward shallowing (HFC's). Identifying HFC's, however, is made difficult because of the high uranium content of the Clear Fork and the lack of a relationship between water saturation and rock fabric. A statistical relationship between porosity and rock fabric is developed, however, that allows porosity to be used as a surrogate for rock fabric, and vertical increases in porosity are interpreted as mud-dominated to grain-dominated fabric successions and used to define HFC's. The HFC's are divided into two rock-fabric flow layers, an upper, grain-dominated and a lower, mud-dominated layer, in order to preserve high- and low-permeability intervals. Permeability data from the outcrop analog in Apache Canyon are used to demonstrate that the vertical variability seen in the log calculations within the rock-fabric flow units does not represent permeable strata but is statistical variability at a near-random scale. Introduction South Wasson Clear Fork field, located in Yoakum County, West Texas, on a small structural high (fig. 1), produces from two thick reservoirsโthe middle and lower Clear Fork. The top of the lower Clear Fork reservoir is the base of the Tubb Formation. This reservoir appears to reach a thickness of 500 ft. The top of the middle Clear Fork reservoir is defined by the change from low water saturation to high water saturation, which corresponds to the top of Leonardian sequence 4, not to the top of the upper Clear Fork Formation (fig. 2). The middle Clear Fork reservoir obtains a thickness of about 700 ft. The interval from the top of the middle Clear Fork to the top of the upper Clear Fork Formation appears to be at residual oil saturation, according to core and production data, and perhaps represents a third reservoir that has remigrated. This study has concentrated on the middle and lower Clear Fork reservoirs in a 1-mi area in the middle of the field (fig. 1). Reservoir Framework A sequence stratigraphic framework has been constructed for the Clear Fork on the basis of geologic descriptions of nine cores and guided by the sequence stratigraphic framework developed at Apache Canyon in the Sierra Diablo Mountains, West Texas (fig. 2). Unfortunately, the Clear Fork section exposed in Apache Canyon represents only the lower Clear Fork, Tubb, and basal part of the upper Clear Fork in the subsurface. Nevertheless, the outcrop observations provide important guidelines for understanding the sequence and cycle stratigraphy in South Wasson.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geophysics > Borehole Geophysics (0.90)
- Geophysics > Seismic Surveying (0.54)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (27 more...)
Abstract This paper describes a straightforward strategy for diagnosing and solving excess water production problems. The strategy advocates that the easiest problems should be attacked first and diagnosis of water production problems should begin with information already at hand. A listing of water production problems is provided, along with a ranking of their relative ease of solution. Conventional methods (e.g., cement, mechanical devices) normally should be applied first to treat the easiest problems-i.e., casing leaks and flow behind pipe where cement can be placed effectively and for unfractured wells where impermeable barriers separate water and hydrocarbon zones. Gelant treatments normally are the best option for casing leaks and flow behind pipe with flow restrictions that prevent effective cement placement. Both gelants and preformed gels have been successfully applied to treat hydraulic or natural fractures that connect to an aquifer. Treatments with preformed gels normally are the best option for faults or fractures crossing a deviated or horizontal well, for a single fracture causing channeling between wells, or for a natural fracture system that allows channeling between wells. Gel treatments should not be used to treat the most difficult problemsโi.e., three-dimensional coning, cusping, or channeling through strata with crossflow. Introduction On average in the United States, more than seven barrels of water are produced for each barrel of oil. Worldwide, an average of three barrels of water are produced for each barrel of oil. The annual cost of disposing of this water is estimated to be 5โ10 billion dollars in the US and around 40 billion dollars worldwide. Many different causes of excess water production exist (Table 1). Each of these problems requires a different approach to find the optimum solution. Therefore, to achieve a high success rate when treating water production problems, the nature of the problem must first be correctly identified. Many different materials and methods can be used to attack excess water production problems. Generally, these methods can be categorized as chemical or mechanical (see Table 2). Each of these methods may work very well for certain types of problems but are usually ineffective for other types of problems. Again, for effective treatment, the nature of the problem must first be correctly identified. Four problem categories are listed in Table 1 in the general order of increasing treatment difficulty. Within each category, the order of listing is only roughly related to the degree of treatment difficulty. Category A, "Conventional" Treatments Normally Are an Effective Choice, includes the application of water shutoff techniques that are generally well established, utilize materials with high mechanical strength, and function in or very near the wellbore. Examples include Portland cement, mechanical tubing patches, bridge plugs, straddle packers, and wellbore sand plugs. A few comments may be helpful to clarify some of the listings in Table 1. First, the difference between Problems 1 and 4 is simply a matter of aperture size of the casing leak and size of the flow channel behind the casing leak. Problem 1, involving casing leaks without flow restrictions, is where the leak is occurring through a large aperture breach in the piping (greater than roughly 1/8 in.) and a large flow conduit (greater than roughly 1/16 in.) behind the leak. The use of Portland cement is favored for treating Problem 1. Problem 4, involving casing leaks with flow restrictions, is where the leak is occurring through a small aperture breach (e.g., "pinhole" and tread leaks) in the piping (less than roughly 1/8 in.) and a small flow conduit (less than roughly 1/16 in.) behind the leak. The use of gel is favored to successfully treat Problem 4. In this paper, the gels under discussion may include those formed fromchemically crosslinking water-soluble organic polymers, water-based organic monomers, or silicates.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia > Middle East (0.93)
- North America > United States > Wyoming > Wertz Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (38 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Casing and Cementing (1.00)
- Well Completion > Well Integrity > Zonal isolation (1.00)
- (3 more...)
Abstract Incomplete or sparse information on types of data such as geologic or formation characteristics introduces a high level of risk for oil exploration and development projects. "Expert" systems developed and used in several disciplines and industries, including medical diagnostics, have demonstrated beneficial results. A state-of-the-art exploration "expert" tool, relying on a computerized data base and computer maps generated by neural networks, is proposed for development through the use of "fuzzy" logic, a relatively new mathematical treatment of imprecise or non-explicit parameters and values. Oil prospecting risk can be reduced with the use of a properly developed and validated "Fuzzy Expert Exploration (FEE) Tool." This tool will be beneficial in many regions of the US, enabling risk reduction in oil and gas prospecting and decreased prospecting and development costs. In the 1998โ1999 oil industry environment, many smaller exploration companies lacked the resources of a pool of expert exploration personnel. Downsizing, low oil prices and scarcity of exploration funds have also affected larger companies, and will, with time, affect the end users of oil industry products in the US as reserves are depleted. The proposed expert exploration tool will benefit a diverse group in the US, leading to a more efficient use of scarce funds and lower product prices for consumers. Summary of Progress During this six-month period the majority of data acquisition for this project was completed with the compiling and analyzing of well logs, geophysical data, and production information needed to characterize production potential in the Delaware basin. A majority of this data now resides in several online databases on our servers and is in proper form to be accessed by external programs such as web applications. A new concept was developed and tested in well log analysis using neural networks. Bulk volume oil (BVO) was successfully predicted using wire line logs as inputs, providing another tool for estimating both the potential success of a well, and the interval to perforate. Regional attributes have been gridded to a 40-ac bin (gridblock) size and our fuzzy ranking procedures have been applied to determine which attributes are best able to predict production trends in the basin, using the average value of the first 12 months of oil production as the value to be predicted. A study to determine the ability of an artificial intelligence system to predict depth using seismic attributes in a Delaware field was completed and the results published. Significant improvements over standard techniques were found particularly when test wells were on the dataset boundary where extrapolation is required. An initial step in programming the expert system was undertaken, and a decision tree program was coded in Java Expert System Shell (JESS) that allows development and tabulation of rules and relationships between rules that can be used by our expert system. This important program allows lists of rules to be entered and easily tested and verified. The design of the expert system itself was clarified and an expanded system was created where several distinct factors such as geologic/geophysical data, trap assessment, and formation assessment will be operated on in parallel to increase efficiency of the overall system. Coding of the Java interface, which users will utilize to access data in the online databases and run the expert system, has begun. Development of the interface will be an important ongoing project over the next year and will eventually tie together the data and the expert system programs coded in JESS while allowing user customization and informative reports of results to be returned.
- Geophysics > Borehole Geophysics (0.76)
- Geophysics > Seismic Surveying (0.56)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Abstract Study of three phase equilibrium has been seen from many literatures. Most research onmodeling ofasphaltene precipitation has remained in qualitative description stage. Even though quantitative calculation of asphaltene precipitation can be seen from some reports. However, quantitative calculation of asphaltene precipitation with three phase flash algorithm is unstable because gas-liquid-solid material balance equations is highly non-linear equations. In the light of general view that there are not heavy hydrocarbons with high molecular weight including asphalt in gas phase, technique of stable asphaltene precipitation calculation is put forward by the paper. The recommended technique in the paper separates gas-liquid-solid equilibrium into two parts: gas-liquid and liquid-solid equilibrium. Liquid phase is a bridge between gas and solid phase and solid precipitates always from liquid phase. Gas-liquid equilibrium is described through EOS and fugacity of asphaltene determined from gas-liquid equilibrium should be compared and accord with fugacity of pure solid phase of asphaltene. In this way, modeling of three phase equilibrium becomes easier and more stable. The validation of the model with experimental data is described also in the paper. Additionally, the paper puts forward gas-liqiud-asphaltene material balance equations which can be deduced from general three phase material balance equations and are not similar to them in forms. Introduction During oil production, Asphaltene precipitation will cause serious problems because it can result in plugging of the formation, wellbore and production facilities. Many literatures gave the description of asphaltene problems and remedies throughout the world. Currently, many cleaning methods of wellbores are being improvised to maintain production, but these methods are time-consuming and expensive. Asphaltene precipitation also occurs frequently during enhanced-oil-recovery by gas injection which impedes seriously the oil recovery. A model for predicting asphaltene precipitation is highly desirable because it would allow the design of production plan with which asphaltene precipitation can be minimized. Some literatures presented modeling technique of asphaltene precipitation with EOS. The presented technique can give quantitative calculation of asphaltene precipitation with three phase flash algorithm. The quantitative calculation with three phase algorithm is unstable because of highly non-linear equations of three phase material balance equations. According to generic opinion that there are not heavy hydrocarbons with high molecular weight including asphalt in gas phase, new technique of asphaltene precipitation calculation is presented in the paper. The suggested technique in the paper separates vapor-liquid-solid equilibrium into two parts -vapor/liquid and liquid/solid equilibrium. Liquid phase is a bridge between gas and solid phase and solid precipitates always from liquid phase. Vapor/liquid equilibrium is described through EOS and fugacity of asphaltene calculated from vapor/liquid equilibrium should be compared and accord with fugacity of pure solid phase of asphaltene. modeling of asphaltene precipitation with the present technique becomes stable. The validation of the model with experimental data is also proved in the paper. Mechanism of Asphaltene Precipitation Many literatures hold the same view that asphaltenes are heavy hydrocarbons which are in colloidal suspension in the oil, stabilized by resins adsorbed on their surface. Changes in pressure, temperature and composition may cause asphaltene precipitation. The mechanism of asphaltene precipitation is still under investigation. There are two possibilities:the asphaltene/resin micelles precipitate essentially unaltered and there is a dissociation of the asphaltene/resin micelles which cause the asphaltene precipitation.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract The Minagish Oolite is a thick undersaturated carbonate oil reservoir in the Minagish field in West Kuwait (Fig. 1) containing several billion STB. It is a mature but relatively undeveloped reservoir. Since discovery in 1959, it has produced 10% of its OOIP under a combination of natural depletion, gas re-injection and aquifer drive. Initial reservoir pressure had declined by about 450 psi prior to the Gulf war in 1990. The well blowouts following the war caused a significant pressure drop of another 700 psi. Following the blowout, plans were made to redevelop the West Kuwait fields and increase the production rate starting in 2001 and to sustain the plateau for at least 5 years. This strategy called for three-fold increase in the production rate of Minagish Oolite reservoir. Since the existing well inventory and the loss of the gas re-injection facility could not sustain the desired plateau rate, additional field development was required. To achieve the production target, a multidisciplinary team was formed to evaluate options. The recommended plan required the drilling of additional producers and installing a field-wide peripheral waterflood. The reservoir, however, presented a number of significant challenges to waterflooding, such as the presence of a substantial and not well defined tarmat near the oil/water contact, and uncertainties of lateral and vertical heterogeneities. In 1997 a full-field simulation model was developed, but this model didn't capture the water movement properly because of insufficient reservoir data at that time. As new core was obtained, a refined reservoir description was developed. Building on lessons learned from the previous full-field model and sector models, a new full-field model was developed which significantly improved well-by-well history matches. Although containing twice as many grid cells, the new model ran up to four times faster than the previous model by making use of the Analytical Aquifer option within the model, improved relative permeability curves and other model refinements. This paper traces the history of the field and the systematic evolution of the development plan. The reservoir simulation efforts including modeling strategy, history matching events, prediction runs, future direction and challenges are also addressed. Introduction Numerical simulators are an important tool for reservoir management, providing management the ability to observe how alternate development plans and operating strategies will affect future oil production and recovery. As additional information is acquired and new technologies are developed, it is necessary to periodically update the reservoir simulation tools. This report identifies the reasons for building a new model, the differences between it and the previous model, and documents the data-sources, files and the methodology used to construct the new model. The previous model (FFM 97) was constructed and initialized in 1997. The model was based on a course 12-layer reservoir description and history matched reservoir performance up through the start of dumpflood water injection. In predictive mode, however, the model did not adequately predict the rapid water movement in the northeast quarter of the field or the arrival of initial water in the peripheral producers. Sector models constructed at the same time indicated that a refined reservoir description that incorporated the observed barriers and high permeability streaks should provide an improved match of the observed water movement.
- Asia > Middle East > Kuwait > Jahra Governorate (0.25)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (46 more...)