bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Compositional Simulation Evaluation of the Santa Rosa, Colorado EF Reservoir, Eastern Venezuela
Authors: Zambrano G. , Granado A. , Rincon A. 
Published: December 2007

ABSTRACT
This report presents the results of a simulation study of the Santa Rosa Colorado EF, RG-14 reservoir located in Eastern Venezuela. The objectives of this study were to determine the quality of the hydrocarbon gas accumulated in the reservoir and to predict oil recoveries under a variety of operating modes. The reservoir contains a condensate gas cap that overlies an oil leg. Depth of the reservoir varies from 6560 ft (1999 m) subsea, at the crest of the dome to 11150 ft (3399 m) subsea on the northern flank.
In order to match field performance history, a significant effort was made in developing a geological model based on the depositional environment concept. A fluid characterization model was also constructed for both, reservoir oil and gas condensate using the Peng-Robinson equation of state.
A satisfactory history match for 36 years of reservoir performance was achieved using a three dimensional, three phases, multicomponent, compo-sitional simulator. The results at the end of the reservoir history match, indicated that the gas present in the reservoir is mainly methane.
A total of five prediction cases were then studied, all intended to provide performance data for technical and economic analysis. The main effects analyzed were: higher gas-oil ratio limit, additional wells, partial and full pressure maintenance and reservoir blowdown.
The main conclusions drawn from the results of this reservoir simulation study were that drilling and reactivating wells in the oil leg and re-locating the injection wells would increase the cumulative production of oil by approximately 9.1 × 106 bbl (1.447 × 106 m3).
On the Investigation of Gravity-Assisted Inert Gas Injection Using Micromodels, Long Berea Sandstone Cores, and Computer-Assisted Tomography
Authors: Chatzis I. , Kantzas A. , Dullien F. A. L. 
Published: December 2007

ABSTRACT
Downward displacement of oil by inert gas injected in a reservoir either at initial oil and connate water conditions or, in a reservoir depleted by waterflooding, results in very high oil recovery efficiencies under strongly water-wet conditions in both unconsolidated and consolidated porous media respectively. Advances made in directional drilling technology and increased understanding of the mechanisms and conditions that maximize recovery efficiencies can make the inert gas injection process of oil recovery1–3 feasible for a wide variety of oil reservoirs. This paper presents experimental results and discussion of a series of experiments designed for the study of: 1) production characteristics under immiscible inert gas driven gravity drainage conditions; 2) microscopic mechanisms of displacements and the determination of the rate of production by gravity drainage in capillary tubes having square cross-section; and 3) fluid distributions and oil bank formation using the x-ray computer tomography (CT) scanning facilities we recently established in our laboratory.
Representation of High Rate Gas Wells in Reservoir Simulation
Authors: Temeng K. O. , Horne R. N. 
Published: December 2007

Abstract
The paper presents an analysis of nonlinear Darcy flow of gas in reservoirs. The equations employed in the analysis are derived from an integration of the fundamental equations describing the flow of real gases in homogeneous porous media. The equations are derived in terms of squares of pressure for radial steady and pseudo steady flow systems.
The analysis indicates that the squared-gradient nonlinearity present in the gas flow differential equation results in a pressure drop and rate relationship symptomatic of non-Darcy flow. The magnitude of the nonlinear contribution to pressure drop is similar to that computed on the basis of non-Darcy theory. This raises the possibility that observed nonlinearities may not be due to non-Darcy effects but merely a result of fluid property variations.
The implication of the findings to the simulation of gas wells is also discussed. The results suggest that for a typical radial grid system with fine grids near the well, it may be unnecessary and incorrect to include additional terms to account for deviations from Darcy flow. In large and rectangular grids however, nonlinear terms are required for correct representation. These additional terms are shown to relate to grid size and shape, and are necessary not because Darcy's law is invalid but because the grids are of finite size.
A Model for Development and Analysis of Gas Reservoirs with Partial Water Drive
Authors: Saleh S. T. 
Published: December 2007

Abstract
In common reservoir analysis computations, the average gas reservoir pressures are erroneously used in the Van Everdingen-Hurst unsteady state equation (VEHE) to calculate water influx. The VEHE requires the pressure at the original gas/water contact (GWC). The incorrect use of the average oil reservoir pressure in the VEHE can lead to a significant error in the results. This study was performed to show the quantitative potential of the error, using a mathematical model.
The mathematical model combines the material balance equation (MBE) for a partial water-drive gas reservoir and the VEHE. The model generates pressure-production data for a conceptual partial water-drive gas reservoir, and for the following two cases: Case A: using average reservoir pressures in the VEHE.Case B: using pressures at the original GWC elevation in the VEHE.
The error is defined as the difference in the calculated pressure performances between cases A and B.
The results of this study showed that the error increases as the aquifer size increases and as the permeability decreases. The maximum error was found to be 14% in the range of reservoir and aquifer conditions studied. This study also showed that gas recovery increases as the permeability decreases, a result which is also reported by Agarawal, Al-Hussainy, and Ramay.8
This paper presents the procedure used to correct average gas reservoir pressure to the original GWC elevation.
Production Forecasts for Alternative Completion Methods in Low-Permeability Gas Reservoirs: Simulation of High-Angle and Horizontal Wells
Authors: Duda J. R. , Kumar H. K. 
Published: December 2007

ABSTRACT
Recently, there has been a heightened interest in the use of horizontal wells to more efficiently drain both oil and gas reservoirs and to compensate for negative producing situations such as coning. The potential applications of horizontal and high-angle wells have led to increased efforts to quantify the expected production increase from these types of completion methods in a variety of geologic settings. Simulation of these alternative completion methods using mathematical models provides a cost-effective method of predicting their performance and allows for sensitivity analysis of reservoir properties.
The performance of horizontal and high-angle completions was simulated for marginal marine and lenticular low permeability gas reservoirs of the Upper Cretaceous Mesaverde Formation underlying the east-central Piceance Basin. Results of the simulations show that production from horizontal wells of intermediate length can be expected to be four times higher than that of vertical, stimulated wells draining large areas. The advantages of high-angle wells in lenticular sandstone environments remain unquantified, but a reasonable potential exists, especially when methane from deeply buried coals is considered.
Validation of Water/Oil Displacement Scaling Criteria Using Microvisualization Techniques
Authors: Sincock K. J. , Black C. J. J. 
Published: December 2007

ABSTRACT
Displacement tests on reservoir core samples provide a direct method for assessing the microscopic displacement efficiency of specific recovery processes in particular reservoirs. They also provide an effective source of data for the comparison of alternative processes.
This paper demonstrates the validity of scaling criteria developed to provide unambiguous relative permeability data from favourable mobility ratio water-oil displacement tests on strongly oil wet and water wet reservoir systems. Microvisualisation techniques were used in conjunction with core displacement tests. These techniques allow a better mechanistic understanding of displacement processes and the location and distribution of residual oil to be established.
Displacement experiments were performed on oil wet and water wet reservoir systems and the resulting pressure and production histories compared with water displacement of solidifiable oil analogues. After solidification of ’residual oil’, water was also replaced by a solidifiable analogue. Good agreement between water-oil displacement characteristics and water-oil analogue displacement characteristics demonstrate maintenance of wettability. Static contact angle tests were also used to ensure wettability alteration was not induced during the fluid replacement technique.
Direct microscopic observation of the fluid distributions at initial and residual saturation using UV fluorescence illumination techniques are presented. The location of initial water saturation is shown to be generally associated with water filled clays and microporous minerals. 'Classical' pendular rings and surface water do not account for the bulk of Swi.
Residual oil in the water wet systems was largely located as discreet blobs as expected. In the oil wet reservoir system examined, residual oil was associated with clay (mainly kaolinite) filled pores. In this case the clays were apparently oil wet. Previously determined scaling criteria and analysis procedures are described and validated.
Transient Pressure Behavior for Horizontal Wells in Naturally Fractured Reservoir
Authors: de Carvalho R. S. , Rosa A. J. 
Published: December 2007

ABSTRACT
This paper presents a mathematical model to describe the pressure behavior for infinite conductivity horizontal wells in naturally fractured formations. A double-porosity medium with pseudo-steady state interporosity flow is considered.
The general method of extending solutions for homogeneous reservoirs to double-porosity models is used. Wellbore storage and skin effects are included by applying the Laplace transformation to the superposition equation. This is also a general and simple method.
Methods of well testing analysis are examined, such as conventional and type-curve matching techniques.
A Reservoir Engineering Study of the Margham Field, Dubai, U.A.E.
Authors: Ernster G. A. , Boiling J. D. , Goecke C. R. , Seader R. A. 
Published: December 2007

ABSTRACT
A reservoir study of the Margham field in Dubai, United Arab Emirates was performed. The main objectives of the study were to combine and evaluate all current production and geologic data to better understand historic reservoir performance and develop reservoir management plans for future field depletion and development. To realize this objective a number of simulation tools were developed to help better understand the condensate recovery mechanisms occurring at Margham. This paper concentrates on the development and application of a full-field computer model of the Margham reservoir.
Due to the complexity of the Margham reservoir special procedures were required to describe the reservoir geology, represent the field's structure, and model gas condensate phase behavior. A successful match of two and one half years of pressure and production data was achieved using a single porosity simulator. Preliminary results from a strip model indicated the dual porosity mechanism to be inappropriate. However specific areas with extensive, sometimes unmapped faults appear to behave in a manner similar to a dual porosity system. These small areas were adequately modeled with the single porosity model by implementing pore volume reductions to represent areas of low sweep efficiency. An aquifer was included in the reservoir description in order to match the field pressure history. Predictions of future field performance emphasized increasing condensate recovery by optimizing current field operations, understanding the benefits of continued gas cycling versus immediate full or partial release of produced gas, and the need for additional infill wells. This paper includes a comparison of actual performance versus the model predicted response during the year following the completion of the study.
Improved Volumetrics with the Computer: Hugoton Gas Field, Kansas
Authors: Swanson Donald C. , Giovinco Sam 
Published: December 2007

ABSTRACT
Mesa Limited Partnership (Mesa) recently completed volumetric analyses of its Hugoton Field gas reservoirs. Assistance was provided by Swanson Geological Services, consultants, who used computer technology to determine total hydrocarbon pore volume.
The Hugoton Field has for years produced gas from multiple heterogeneous carbonate reservoirs. Present spacing does not drain the field. Volumetrics, properly calculated, should result in a more accurate and realistic determination of not only the amount of gas in place but also its original spatial distribution. Computer technology was used to eliminate errors often encountered with volumetric methods.
When reservoirs are superimposed, operators often add up the data for all units at each well, and the sums are contoured. This leads to errors. Stacked reservoirs should have their thicknesses individually distributed. Similar treatment is desirable for all contributing parameters to volumetrics.
Hydrocarbon pore volume is a product of thickness, porosity, and saturation. These parameters should be individually contoured, after which the percent hydrocarabon pore feet and total hydrocarbon pore feet can be determined by cross-contouring or computer methods. Hydrocarbon pore feet should not be calculated at wells and then contoured.
Mesa's Permian Chase Group reservoirs consist of seven separate units: Herrington, Krider, Winfield, Towanda, Florence, Fort Riley, and Wreford. Typical thicknesses vary between 15 and 35 feet and porosities and water saturation from 6 to 25 percent and 10 to 90 percent, respectively.
Mesa analyzed over 4 00 wells that had density or sonic logs. These were used for distribution of porosity and hydrocarbon saturation. About twelve hundred wells were used for thickness data.
Radian CPS software and two Compaq Deskpro 286 PC's were used for the volumetric study. Individual section polygons had been digitized and were used with the total hydrocarbon pore feet grid to calculate section by section volumes. These were then used to determine reserves.
Using accurate volumetric procedures will not necessarily result in reserve increases; however, in the case of the Mesa project, a significant gas volume increase resulted over that previously determined by well performance.
Putting Geology into Reservoir Simulations: A Three-Dimensional Modeling Approach
Authors: Johnson C. R. , Jones T. A. 
Published: December 2007

ABSTRACT
Eighteen years ago Exxon initiated the development of a three-dimensional geological modeling program to automate the generation of geologic maps and cross sections from exploration data. This program is also well suited for providing a highly complex reservoir description for reservoir simulation and has become a standard operating procedure for many of Exxon's simulation projects.
Because these models are directly interfaced to the reservoir simulator, the reservoir engineer can easily utilize the complex reservoir description provided by the geologist for field development planning. In addition, the reservoir engineer can routinely and readily update his model with new data or interpretations and quickly provide consistent maps and sections for assessing results of development drilling.
Evaluation of Oil Recovery From a Thin Oil Column by a Horizontal Well in the Oseberg Gamma North Reservoir
Authors: Fantoft S. , Krogh P. K. , Pollen S. 
Published: December 2007

ABSTRACT
In the Gamma North Structure a thin oil zone is sandwiched between a gas cap and an aquifer, and the oil production rates are limited by the gas and water coning. Compared to vertical wells, horizontal wells will reduce the coning tendencies and may lead to a substantial increase in the oil recovery. The orientation of the horizontal well is important forthe recovery in a structure like Gamma North, with dipping layers and high permeability anisotropy.
Field Experience with a Novel Calcium-Tolerant Fluid-Loss Additive for Drilling Muds
Authors: Plank J. P. , Hamberger J. V. 
Published: December 2007

ABSTRACT
A novel sulfonated polymer used as a fluid loss additive in water base drilling fluids is introduced. Major features of this 100% synthetic polymer are temperature stability up to 400°F (200°C), salt tolerance up to saturation, hardness tolerance to 75,000 ppm calcium ions and complete neutral effect on viscosity. A remarkable thermal stabilizing effect on polysaccharide fluid loss reducers like e.g. starch, CMC, PAC, HEC, CMHEC is found. The mode of action of the novel polymer is investigated by means of SEM photos from drilling mud filter cakes.
Field experience with the novel polymer includes such fluid systems as fresh water, sea water, salt saturated, KCl/polymer, dispersed muds and solids free brines. Field data from over 20 wells in Europe and North America both on and offshore are presented and analyzed.
Field examples for the thermal stabilization effect of the novel polymer on starch are given. The novel polymer extends the thermal stability of starch from 245°F (120°C) to 295°F (145°C). More than a dozen German Zechstein. wells have been drilled with this system to depths up to 15,750 ft (4800m), BHST to 280°F (137°C) and calcium contamination up to 42,000 ppm.
Cellulose type polymers such as CMC, PAC, HEC and CMHEC were thermally stabilized by the novel polymer. A North German gas well using CMC for filtration control added the novel polymer, reduced the HPHT filtrate from 22 ml to 12 ml and cut the daily maintainance rate of CMC by half. Offshore Norway a KCl clay-free fluid with CMHEC was extended to over 320°F (160°C) by addition of the novel polymer.
The novel polymer significantly reduces the HPHT filtrates of dispersed systems. On an offshore Gulf of Mexico well the HPHT filtrate was reduced from 45 mls to 5.3 mls in a lignosulfonate sea water mud with 5.25 ppb of the novel polymer being added. A Central Texas well with a lignite fresh water mud required lime treatment to combat a heavy CO2 influx resulting in calcium contamination. The novel polymer lowered the HPHT filtrate from 35-40 to below 20 mls.
In a highly deviated Mobile Bay (USA) well a combination of the novel polymer and a lignite-phenolic resin yielded temperature stability over 500°F (260°C) and reduced the HPHT by 80%.
A Systematic Approach: The Key to Successful Core Analysis
Authors: Heaviside J. , Salt H. J. 
Published: December 2007

Abstract
The application of core analysis to provide data for reservoir evaluation is not a new science but has seen continued research activity over a long period. Core analysis is complex containing many stages between the reservoir and the final measurements and interpretation. To ensure the data produced is valid every step along this route must be handled with equal attention. This paper describes an integrated set of procedures for the generation of valid data for prediction of field waterflood performance.
Core samples chosen must be representative of the reservoir in all respects: lithology, petrography, permeability and porosity. Sample preparation must ensure that fluid saturations and distributions (initial water saturation, S.) and wettability are equivalent to their native state. Finally the measurements themselves must be made such that displacement is representative of the reservoir scale and is not distorted by any core scale artefacts.
The particular study described was conducted in support of reservoir engineering studies of waterflood performance in the Welton reservoir, an onshore field in thé UK. It is located in the basal Silesian sandstone of the East Midlands. The reservoir unit is an amalgam of river channel deposits with intervening shales. The work was carried out as part of an overall objective to improve the definition of reservoir properties and hence enable more accurate prediction of reservoir behaviour.
The systematic approach is described, beginning with sample selection using X-ray CT and petrography to ensure representative lithology.
This is followed by an investigation to establish representative wettability for the Welton fieldand to identify a suitable preparation method. This was then used in generation of capillary pressure data using the centrifuge technique and in waterflood experiments at realistic flow rates. Finally a numerical method is used to interpret the corefloods and obtain representative rock relative permeability data.
The Petroleum Industry and the Environment
Authors: Bloemendal J. W. 
Published: December 2007

ABSTRACT
During the last few decades the Petroleum Industry has made ever increasing efforts to prevent damage to the environment in the course of all its operations. In consultation with the public, governments and other authorities, the international oil industry studies the impact of wastes on the environment and presents well balanced proposals for international legislation.
The paper reviews quantatively the various sources of pollution, and the degree of damage caused by actual con-centrations.
Referring to numerous studies the paper evaluates measured effects to distinguish between actual and apparent damage, the rate of decomposition and the differences between stagnant and flowing waters.
The preventive measures to reduce or eliminate pollution, as well as methods to remove harmful agents from effluents are listed. The effectiveness and relative economy of the various methods are discussed as a balance must be struck between protection obtained and the costs involved.
Existing and forthcoming legislation is given, with due attention to the trend for international standardization. Although the main focus is on offshore drilling and production, the onshore operations and the relative importance of pollution in exploration, transport, refining and distribution are mentioned.
The report has been written from the actual situation in The Netherlands, but where different approaches are practiced in other North Sea operations they are mentioned.
Effects Of CO2 Attack on Cement in High-Temperature Applications
Authors: Shen J. C. , Pye D. S. 
Published: December 2007

ABSTRACT
Well cement carbonation by CO2 containing gas or brine can happen to CO2 flooded oil fields, gas fields and geothermal fields. Due to the Unocal's interests in these applications, especially in the high temperature geothermal wells, a field and laboratory testing program was conducted to examine the effects of CO2 gas on high temperature cement.
Wellhead cement samples from geothermal wells in the Brawley and Geysers fields were collected and analyzed for carbonation. The degree of cement carbonation was found to be dependent on factors such as, temperature, CO2 content in the fluid and location. Both the carbonated and the uncarbonated cement have developed extensive fractures and fine fissures in the matrix due to thermal cycles. The carbonated cement has an acceptable level of compressive strength, but its permeability is normally higher than desired.
Preliminary results from laboratory cement carbonation tests under simulated downhole high temperature, high pressure conditions are presented. A new analytical technique was used to measure the depth of carbonation. The CO2 diffusion coefficient in the cement solid matrix was estimated with this technique.
By comparing field, lab and published data, the carbonation mechanism in high temperature cement is found to be a function of several parameters, i.e., temperature, CO2 content in the fluid and cement additives.