bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas-Condensate Well Performance Using Compositional Simulator: A Case Study
Authors: Bengherbia Mourad , Tiab Djebbar 
Published: December 2007

Abstract
The TFT gas-cap field in Algeria produces a lean gas condensate from an Ordovician reservoir. The dewpoint pressure (2619 psi) is approximately the initial reservoir pressure (2683 psi). The pressure reaches the dewpoint within a short production time, and then drops below the dewpoint. This pressure drops causes a loss of productivity, and high condensate saturation builds up near the wellbore could lower gas productivity.
To simulate the depletion process, the Peng-Robinson EOS was developed to characterize the fluid from a well data. A tuned model matched the experimental PVT data like Constant Composition Expansion (CCE), and Constant Volume Depletion (CVD) that are reliable and give a high degree of match results. This is performed by pseudoizing the EOS components from 11 to 7. A splitting method is discussed, and refers to the procedures of dividing the heptanes-plus fraction into hydrocarbon groups with a single carbon number, which are described by the same physical properties used for components.
A compositional simulation is performed to study the behavior of gas condensate fluid, and to show the phenomenon of condensation of liquid in the reservoir when the pressure drops below the dewpoint pressure. Because the compositional computing time increases significantly with the number of component used, the pseudoized fluid components discussed before are used to reduce the computing time.
An agreement between the tuned Peng-Robinson EOS and experimental PVT data leads to a good depletion process for use in production simulation. The simulation model yields high-quality match with the test data, such as the average pressure, gas production, and liquid (condensation), which leads to good performance predictions.
A good understanding of the gas condensate reservoir, when operating above and below the dew-point, and how this reservoir is affected by three zones, the inner, the middle, and the outer, where the pressure drops below the dew-pressure, and the variation of liquid and vapor phases for each component in an other hand.
Evolution of Dolomitic Completion/Stimulation Optimization in Indian Basin Field, Eddy County, New Mexico
Authors: Peavy M. A. , Weaver R. T. , Torres G. 
Published: December 2007

Abstract
This paper will provide a case study of the evolution of the stimulation and completion methods used to redevelop a dolomite formation located in Indian Basin field, New Mexico, USA which commenced in mid-1990 (Fig. 1). The field, discovered in 1963, produces from the Upper Pennsylvanian formation, a fractured, vuggy dolomite located at approximately 7500 ft. with a gross productive interval of 300 ft. Field production has reached an all time high as a result of the utilization of technology in a quest for the optimal completion process during this time. Significant completion/stimulation challenges involved reservoir, environmental and safety, drilling, and production issues. Reservoir concerns involved zone stratification, low bottomhole pressure (400-1200 psi), and high H2S levels (8,000 to 10,000 ppm). Four drilling methods were used over the past seven years, which impacted completion stimulation design. These included water based mud with lost circulation materials, air drilling, dry drilling, and an aphron "at-balance" system. Producing the wells involved a process called "co-production" whereby high rates of water are produced along with gas for sustained time periods.
This study will compare well data on twenty wells drilled by Kerr-McGee where gas productivity ranges from 500 MCFPD to 10,000 MCFPD/well. Well stimulation was one of the most critical components of the development process due to the nature of the rock where significant permeability streaks may dictate the degree of stimulation coverage throughout the zone. Approximately 40 stimulation treatments will be summarized and reviewed to highlight the evolution and success of the stimulation methodologies utilized today. Treatments ranged from small volume straddle packer acid jobs to high rate foamed acid fracturing stimulations.
This paper will provide historical production information comparisons used to shape the stimulation process. Other technologies were utilized during this time to better define an optimized completion process. The impact of core analysis, acid studies utilizing core material, FMI logs, production logs, and post stimulation treatment logs will be addressed in the paper. These technologies all played a role in revealing formation characteristics that led to the current "best practices" utilized by Kerr-McGee in the field.
Acidizing Performance in Hassi R'Mel Field, Algeria
Authors: Meddahi Fateh , Tiab Djebbar 
Published: December 2007

Abstract
Recently, matrix stimulation treatment was used for the first time in the Hassi R'Mel field in Algeria, one of the major gas condensate fields in the world, to increase the production of wells supposed to be producing below their potential, because of damaging events occurring during drilling, completion, and workovers. Acidizing jobs were conducted by three different companies. Three different kinds of mud acid system were used to stimulate a total of thirty-four wells during 1998 to 2000.
In this study, the primary goal is to determine to what extent our predetermined objectives have been reached, and identify the conditions that lead to a greatest response to acidizing. For this purpose, laboratory evaluation was performed to identify formation properties and its response to different acid formulas, used or proposed by service companies. Pre- and post-stimulation engineering data were collected and analyzed. Finally, economic evaluation of each well and for the whole field is performed.
The results of this study show that the reservoir was highly damaged by drilling and workover fluids. All acid formula were found to be effective in removing the damage, however insoluble precipitates capable of blocking pore throats were generated, especially in layer A. This layer of Hassi R'Mel field is described as dirty sand. Field results showed that: (a) layer A did indeed suffer production loss, (b) corrosion problems are severe, (c) chemical diversion proved to be ineffective in acidizing multi-layer wells, (d) damage is not completely removed, and (e) cleanup of wells takes long periods of time. These drawbacks can be reduced if: (a) corrosion inhibitor is used before well flowback, (b) more acid volume is injected, (c) overflush solution volume is three times the volume of main treating fluids, (d) Acid concentration is decreased, and (e) Chemical diversion is used together with mechanical diversion to treat multi-layer wells.
Gas Storage Performance in a Fractured Formation
Authors: Gerov Lubomir G. , Lyomov Shteryo K. 
Published: December 2007

Abstract
This paper presents analysis of the performance of Chiren Underground Gas Storage Field located in Northwest Bulgaria. The storage was built in a depleted gas condensate reservoir. The producing formation comprises of fractured multi layered carbonate and sandstone rocks. The gas field/storage has been object of several controversial studies.
The paper includes analysis of the influence of rock deformations, water drive, and effect of the capillary processes, from the period of gas field to the recent days. In the study, data from the 30 years history period, laboratory data as well as mathematical simulation are used.
The results show significant influence of the heterogeneity of the formation, production injection schedule, and the well spacing. Progressive time dependent gas dis-balance is observed. Evaluation shows that it is in the range of 1/3 the peresent stored gas volume in the reservoir. Well logs prevail good state of the production casing and luck of gas migration in upper formations. Simulation shows that the main reasons for the gas dis-balance and formation of zones with higher pressure as a result of water movements, formation rock deformation and well water cut. The inadequate reservoir management has neglected those factors and it seems it's the main reason for the bad reservoir performance.
Evolution of Completion Practices and Wellbore Geometry: A Sour Gas Carbonate Reservoir in the Wyoming Thrustbelt
Authors: McInnis N. A. , Harting T. A. , Vaitl J. D. 
Published: December 2007

Abstract
Successful redevelopment of the giant Whitney Canyon-Carter Creek field began in 1995, ten years after initial drilling was completed. Keys to this exploitation success were a better technical understanding of the reservoir, the evolution of completion practices and enhanced wellbore geometries. Application of these learnings fueled the infill program, producing an incremental 134 Bcf since 1995, with initial well rates up to 60 MMcf/D.
Pore volume re-interpretation in 1994 identified a potentially large, under-developed resource. Early drilling confirmed this potential. To effectively access these reserves however, historical completion practices had to be redefined, given the reservoir's fluid sensitivity and the need for better stimulation in this low permeability, pressure-depleted system.
Completion optimization focused on acid system design, diversion and debottlenecking. Emulsified acid and CO2-energized fluids increased etched half-length and load recovery. Better zonal isolation was achieved in a progression from bridge plugs to reservoir stresses and sparse perforating. Further, tubulars were upsized to reduce pressure losses due to friction.
Wellbore geometry evolved from vertical to high angle, extended reach wells. These increasingly complex wellbores contacted more reservoir, targeting improved rock quality and the natural fracture system. Each of these factors contributed to improved rate and recovery, but provided many operational challenges.
New Completion Techniques Improve Production Rates in a Maturing Gas Reservoir
Authors: Stromquist Marty L. , Boulton Ken , Pangracs Steve 
Published: December 2007

Abstract
To ensure continued economic success of drilling new wells in maturing gas or oil fields, it is often necessary to find methods to reduce well costs or to improve stimulation efficiency. Imperial Oil Resources applied the emerging technologies of grass-roots coiled tubing drilling and coiled tubing fracturing in the Tilley Milk River Gas Unit. This paper will describe the impact of these new technologies on well economics and production.
In 2000, grass-roots coiled tubing drilling was used on 9 wells in the Tilley field. Drilling costs were 15% below estimates. Coiled tubing fracturing was also applied to the wells drilled in 2000. First year average gas productivity was 50% higher than expectations, leading to investment reappraisals indicating that well reserves were 30% above previous estimates. In 2001 an additional 25 wells were fracture stimulated with coiled tubing also showing increased production rates.
Stimulation Techniques for Low-Permeability Reservoirs with Horizontal Completions that Do Not Have Cemented Casing
Authors: McDaniel B. W. , Willett R. M. 
Published: December 2007

Abstract
Existing literature offers numerous success stories for stimulating cased/cemented horizontal completions in low-permeability reservoirs.1–8 However, operators who are faced with limited producing potential need to reduce well costs. Completing the horizontal section openhole or with a noncemented liner is attractive. In low-permeability reservoirs, production from such completions has often been below expectations, and sometimes even commercially unfeasible. This is especially true when we consider only completions in reservoirs other than fractured chalks.
To achieve proper stimulation with a technique such as fracture acidizing or hydraulic fracturing with proppants, operators must incorporate an economic and effective method for controlling the fluid or proppant placement. Currently, few well-proven technologies exist for controlling fracture placement in noncemented wellbores. In some cases, high risk or very high cost is associated with these technologies, depending on reservoir conditions or the potential for production improvement.
This paper examines several approaches that have been used to solve these problems, and presents some of the reasons for their mechanical and/or economical success or failure.
Generally, the successful use of either conventional fracturingtreatments or waterfracs (with very little or no proppant) will require some method of controlling fracture placement along the horizontal for significant production improvement. Controlling fracture placement is usually also required for effective fracture-acidizing of carbonate formations. Case histories from Canada and west Texas are included, and other examples within the literature are cited.
New Fluid Technology Allows Fracturing Without Internal Breakers
Authors: Weaver J. , Schmelzl E. , Jamieson M. , Schiffner G. 
Published: December 2007

Abstract
A recent development in fracturing fluid technology is the introduction of a unique fracturing fluid that requires no internal breakers. The new system will be referred to as low molecular weight fracturing (LMWF) fluid. Despite very robust and stable rheological properties during pumping, LMWF fluid returns to its original low viscosity shortly after fracture closure. The distinctive properties of this fluid will be presented, along with a discussion of the influence that this system is expected to have on the effectiveness of fracture stimulation treatments. Case history information will also be reviewed and the paper will attempt to explain well performance as it relates to "effective" fracture geometry, and the effect that fracturing fluid properties can have on this important stimulation design parameter.
Acid Stimulation of Sour Wells
Authors: Delorey J. R. , Vician D. N. , Metcalf A. S. 
Published: December 2007

Abstract
Production of Hydrogen Sulfide (H2S) gas in oil and gas wells has increased over the last few years. These sour (H2S Producers) wells have been successfully acid stimulated for many years. Wellbore acid washes, high rate squeeze treatments and acid fracs have been the norm for stimulating wells in carbonate formations. However, to accomplish this there are many problems related to the interaction of the treatment fluids and the H2S. These can result in excessive corrosion, unwanted precipitants, metal cracking, etc.
In recent years, the practice of drilling horizontal wells has led to the technique of underbalanced acid washing. Controlling corrosion, metal fatigue and unwanted precipitants when using this technique in sour formations presents a special challenge. The resulting interaction of the H2S and acid additives, especially corrosion inhibitors has been the primary focus of concern.
This paper describes test equipment and procedures designed to investigate H2S and acid additive interactions. Test results with a range of inhibitors and additives designed to minimize formation damage and protect coiled tubing and tubular steels are provided. Specifically, weight loss, pitting and precipitation products are listed.
Safe and Economic Gas Wells through Cement Design for Life of the Well
Authors: Ravi K. , Bosma M. , Gastebled O. 
Published: December 2007

Abstract
Natural gas is one of the cleaner sources of energy, and our challenge is to produce it safely and economically. The extreme operating conditions that occur in gas-storage and gas-producing wells could cause the cement sheath to fail, resulting in fluid migration through the annulus. Designing cement sheaths that can withstand the stresses induced by the various operations and maintain integrity during the life of the well will help minimize the risk of cement failure.
A design procedure has been developed to estimate the risk of cement failure as a function of cement sheath and formation properties and well-stress loading. A few examples of the loading are cement hydration, pressure testing, gas injection, and gas production. The design procedure simulates the sequence of events from drilling to cement hydration, hydraulic fracturing, injection, production, etc. Cement failure modes simulated are de-bonding, cracking, and plastic deformation. An appropriate nonlinear material model, including cracking and plasticity, is used in the analysis.
The sustained casing pressure observed on a number of wells after they have been put on production emphasizes the need to design a cement sheath that will maintain integrity during the life of the well. Field cases and applications are discussed. From the process discussed in this paper, one can estimate the risk of failure of different cement systems and select the system that can help minimize the overall cost. The process should improve the economics of constructing and producing gas and oil wells and also improve the safety due to the reduced risk of zonal isolation failure.
General Correlation for the Effect of Non-Darcy Flow on Productivity of Fractured Wells
Authors: Settari A. , Bale A. , Bachman R. C. , Floisand V. 
Published: December 2007

Abstract
The paper describes a systematic study of the effect of the turbulence on productivity (or injectivity) of fractured wells. It extends significantly beyond previous work, and shows its limitations.
A new correlation has been developed, based on over 2,000 high-accuracy numerical solutions for vertically fractured well for a simple geometry. The base correlation was developed for fully penetrating fracture and it is applicable to liquid and high-pressure gas systems. The general correlation for fully penetrating fracture is a function of the two dimensionless parameters and two other parameters, which can be chosen as fracture conductivity and permeability. Additional results are provided for the effect of partial perforations on a fully penetrating fracture. As a limiting case, this scenario can represent also transversely fractured horizontal well. The final correlation therefore involves 5 variables.
The results show that the conventional notion that turbulence is important only in high rate gas wells is often false. Turbulence effect on productivity or injectivity can be significant for liquid flow in high permeability formations, with limited perforations and especially in transversely fractured horizontal wells.
Residual gas saturation investigation of a carbonate reservoir from Western Canada
Authors: Ding Minghua , Kantzas Apostolos 
Published: December 2007

Abstract
The value of residual gas saturation to water influx is a key factor for estimating recoverable reserves in gas reservoirs overlaying active aquifers or natural gas storage reservoirs. Most of our previous work investigated the determination of residual gas saturation for sandstone reservoirs with high values of porosity and permeability. However, vast gas resources are trapped in low porosity and permeability carbonate reservoirs. A number of cores from a Western Canada carbonate reservoir were tested as part of an experimental program to determine the residual gas saturation at ambient conditions. Primary and secondary spontaneous imbibition tests were performed on each core plug. Different initial water saturation conditions were used and the obtained results were compared. The centrifuge technique was used to set the initial water saturation. The initial imbibition rate was found to be the key for residual gas saturation. The effects of core plug properties were addressed. Our work also addressed the prediction of field scale recovery by application of simple scale-up laws. Different simple predictive models, which were used to fit sandstone reservoirs successfully, were tested as part of this work. The laboratory experimental results were also compared with log data to predict gas production and gas recovery of reservoir under different matrix block sizes.
Resolving the Completion Engineer's Dilemma: Permanent or Retrievable Packer?
Authors: Triolo M. T. , Anderson L. F. , Smith M. V. 
Published: December 2007

Abstract
Traditionally, completion engineers have faced a dilemma when deciding whether to run a large bore, hydraulic set, permanent, or retrievable packer. Thanks to advances in cutting technology, this decision is no longer an either/or proposition. The innovative alternative is the removable packer.
This paper will address the development of a removable packer that combines the best features of both permanent and retrievable packers: large bore, high performance, simple design, and flexible retrieving options. The paper will trace the development of the technique from stack-up testing to the maiden run and retrieval of the first removable packer in the Milne Point field, Alaska. Through analysis of this case history, the paper will address challenges faced, problems solved and lessons learned that are now being applied to future enhancements of the removable packer technique.
Effect of Variable Injection Rate on Falloff and Injectivity Tests
Authors: Hachlaf Houari , Tiab Djebbar , Escobar Freddy H. 
Published: December 2007

Abstract
Numerous full field water-flooding projects are currently under way throughout the world to improve recovery. In many large oil fields water injection is initiated during the early stages of reservoir development. Exploratory wells are tested for injectivity, and injectors are tested during the field operation. As in production tests, it is quite difficult, if not impossible, to maintain a constant rate during an injection test. Any small variation in the injection rate, if not accounted for, may lead to considerable error in the calculated results. In some falloff tests, the pressure at the wellhead drops below the atmospheric pressure. When this occurs, the tubing becomes partially empty, leading to a change in the wellbore storage coefficient. A falloff of long duration is not suitable because the injection is stopped which is uneconomic.
In 1963, the two-rate flow test method was introduced. This was designed to eliminate the disadvantages of buildups and drawdowns. The disadvantage of the two-rate flow test is that the flow rate during the second flow period must be constant which leads to considerable errors in the results. To eliminate some of these difficulties, it was proposed a modification consisting of following the second rate with a rate increase. However it still required constant-rate flow. Another technique using a plot of Pwf vs log ([t+∆t)/∆t]+q2/q1log∆t to relate to system transmissibility was also introduced. This had a lacking on accuracy which was corrected later on by other study. Another researcher removed the constant rate requirement during the second flow period. Thus the test is easier to run and any fluctuation in rate is accounted for in the calculations. To overcome the problems encountered when using drawdown type curves to analyze buildup test, a technique was developed to account for the dependence of the producing time especially when the producing period is short or the flow rate is variating. This method was extended to include analysis of data from two-rate tests and multiple rate tests.
Multi-rate injection pressure test should be designed to avoid most of the above problems. In this paper, new relationships for a multi-rate injection pressure test in a non-unit mobility ratio system were developed. The pressure derivative was introduced to analyze such a pressure transient tests. Estimation of reservoir parameters was performed by the application of the Tiab’s Direct Synthesis Technique, which uses exact analytical solutions to obtain reservoir parameters, was applied to solve different possible cases.
The proposed interpretation technique was tested during simulated examples and comparing the results to those obtained from conventional techniques. A comparison between the use of equivalent time (the rigorous method) and real time to analyze a multi-rate injection test was made.