bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Diluted Consolidation Systems To Improve Effectiveness of Proppant Flowback Remediation—Laboratory and Field Results
Authors: Nguyen Philip D. , Weaver Jimmie D. , Rickman Richard D. , Sanders Michael W. 
Published: March 2009

Summary
Individually, coiled tubing (CT), consolidating fluids, or pressure-pulsing tools do not represent new technology. However, the combination of these technologies offers a viable solution to the proppant flowback problem after the proppant has been placed in the fracture. This paper presents the results of laboratory studies and field case histories of a remedial treatment technique through use of a low-viscosity consolidation fluid system that is placed into the propped fractures by CT or jointed pipe coupled with a pressure-pulsing tool. The treatment fluids are designed to provide consolidation (for previously placed proppant) near the wellbore to glue the proppant grains in place without damaging the permeability of the proppant pack.
Laboratory flow testing indicates that the proppant pack in a fracture model under closure stress only requires low-strength bonds between proppant grains to withstand high production flow rates. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the well-bore into a cohesive, consolidated, yet highly permeable pack. Field case histories are presented and the treatment procedures, precautions and recommendations for implementing the treatment process are discussed. One major advantage of this remedial treatment method is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and the length of the perforated intervals without mechanical isolation between the intervals. The fluid-placement efficiency of this process makes remediation economically feasible, especially in wells with marginal reserves.
Hydraulic-Fracture-Model Sensitivity Analyses of a Massively Stacked, Lenticular, Tight Gas Reservoir
Authors: Green Christopher A. , Barree Robert D. , Miskimins Jennifer L. 
Published: March 2009

Summary
This paper assesses critically the importance of various inputs that are used for a common method to develop a simulator model of hydraulic fractures (HFs) in geologically complex, fluvial, tight gas reservoirs. A planar 3D fracture simulator is used with a fully coupled fluid-/solids-transport simulator. The geomechanical rock properties from logs (Young's modulus, Poisson's ratio, and Biot's constant) and diagnostic minifracture injection tests of individual sandstone reservoirs were investigated to assess their importance in developing a valid stress model.
This paper describes the investigations by use of a model matched previously with both net surface pressure and microseismic/tiltmeter data. From these results, it is possible to obtain a better understanding of how fractures grow and interact with complex fluvial reservoirs, allowing operators to optimize field-well performance and completion methods better in these geologic settings. Additionally, the minimum critical data recommendations necessary to develop such a model have been identified and will aid operators in developing their data-acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extended to other similar geologically complex reservoirs worldwide.
Analysis and Comparison of Decline Models: A Field Case Study for the Intercampo Oil Field, Venezuela
Authors: Dou Hong'en , Chen Changchun , Chang Yuwen , Fang Yanjun , Chen Xinbin , Liu Wei , Cai Wenxin 
Published: March 2009

Summary
Intercampo oil field, which contains unconsolidated reservoirs driven by edge water and bottom water, is characterized by heavy oil with mid-high permeability and high oil saturation. The three classical models of the Arps model were applied in 13 horizontal and vertical wells in the oil field; also, the paper introduces two models that are not widely applied for decline analysis and forecasting in the wells. Decline features between vertical and horizontal wells were compared. The results accord well with the actual data from the oil field. The authors point out that these decline analysis models are applicable not only for vertical wells but also for horizontal wells. The authors would like to emphasize that four decline models discussed in the paper. In regard to screening and comparison of decline analysis models, this paper illustrates how to select and use a model, as well as the model's application conditions and their features. The screened models are recommended for production performance analysis of wells, reservoirs and oil fields.
Bati Raman Field Immiscible CO2 Application—Status Quo and Future Plans
Authors: Sahin Secaeddin , Kalfa Ulker , Celebioglu Demet 
Published: March 2009

SummaryThe Bati Raman field is the largest oil field in Turkey and contains approximately 1.85 billion bbl of oil initially in place. The oil is heavy (12°API), with high viscosity and low solution-gas content. Primary recovery was less than 2% of oil originally in place (OOIP).Over the period of primary recovery (1961–86), the reservoir underwent extensive pressure depletion from 1,800 psig to as low as 400 psig in some regions, resulting in a production decline from 9,000 to 1,600 STB/D.In March 1986, a carbon-dioxide (CO2)-injection pilot in a 1,200-acre area containing 33 wells was initiated in the western portion of the field. The gas-injection was initially cyclic. In 1988, the gas injection scheme was converted to a CO2-flood process. Later, the process was extended to cover the whole field.A peak daily production rate of 13,000 STB/D was achieved, whereas rate would have been less than 1,600 STB/D without CO2 application. However, the field has undergone a progressive production decline since 1995to recent levels of approximately 5,500 STB/D. Polymer-gel treatments were carried out to increase the CO2 sweep efficiency. Multilateral- and horizontal-well technology also was applied on a pilot scale to reach the bypassed oil. A water-alternating-gas (WAG) application has been applied extensively in the western part of the field. Current production is 7,000 STB/D.This paper documents more than 25 years of experience of the Turkish Petroleum Corporation (TPAO) on the design and operation of this full-field immiscible CO2-injection project conducted in the Bati Raman oil field in Turkey. The objective is to update the current status report, update the reservoir/field problems that TPAO has encountered (unpredictable problems and results), and provide a critical evaluation of the success of the project.
EOR Pilot Tests With Modified Enzyme—Dagang Oilfield, China
Authors: Feng Qing-xian , Ma Xian-ping , Zhou Li-hong , Shao Ding-bo , Wang Xiao-lin , Qin Bao-yan 
Published: March 2009

Summary
Micro- and macroevaluations were conducted to understand modified-enzyme enhanced-oil-recovery (EOR) mechanisms using various fluids. Huff'n'puff and flooding tests were carried out with variable modified-enzymes concentrations in several reservoirs. The resulting production performances were improved considerably. At reservoir temperature 50 to 80°C, laboratory experiments indicated that the modified enzyme solution was adaptable to both light and heavy oil and was not sensitive to minerals, water with bivalent cation (1000 mg/L), or high salinity (10%). The enzyme working performances were enhanced further with microorganism occurrence in the solution. The micromodeling experiment reveals that spontaneous emulsification and solubilization can take place between the modified enzyme and crude with emulsion particles of 2–6 μm in diameter, which are produced through stripping as a result of solubilization. Core desorption and flooding experiments suggest that desorbed crude volume and displacement efficiency are related to modified-enzyme concentrations that usually ranged from 5 to 10%, with the optimum being 8%. In optimal conditions, recovery can, on average, be increased by 16.9%. Experiments also proved that the modified enzyme and crude oil could form an emulsion, but the emulsion was not stable. One specific pilot test with modified enzyme had achieved additional oil production of 22,869 bbl.
Stimulation of Bypassed Pay Zones in Existing Wellbores
Authors: Moreno J. W. , Engler T. W. 
Published: March 2009

SummaryA significant portion of the US gas resources is located in low-permeability, bypassed pay zones, within multilayered sandstone-shale sequences. Acquiring these resources leads to operational and design difficulties in stimulation, particularly if the target zone is bounded above and below by existing producing zones. The objective of this work was to evaluate the impact of adjacent, existing producing zones on the stimulation design and therefore production performance of the bypassed payzone.To investigate this problem, a 3D planar, hydraulic fracture propagation model was constructed and superimposed on a 3D flow model. The physical model comprises three layers, the top and bottom representing previously stimulated and producing layers, and the middle layer the target or bypassed layer. The impact of lithology, fracture length, and total stress variations over time on the fracture conductivity, fracture efficiency, and average reservoir pressure were investigated.Evidence of pressure depletion of the target layer was observed caused by production of the upper and lower layers. The degree of depletion is dependent on the fracture length and lithology of all of the layers. That is, the ability to propagate a fracture in the target layer was a strong function of the shale content and to a lesser extent, on the hydraulic fracture length of the bounding layers. Increased shale content in the target as well as the bounding layers resulted in a decrease in fracture conductivity of the target layer. However, an increase in fracture length did not necessarily result in a decrease in fracture conductivity of the target layer.The study includes examples of stimulating the Menefee formation in the San Juan basin.
An Investigation of PVT Effects on Geochemical Fingerprinting of Condensates From Gas Reservoirs
Authors: Al-Meshari Ali A. , Kokal Sunil L. , Jenden Peter D. , Halpern Henry I. 
Published: March 2009

Summary
One of the tools used for the characterization of gas reservoirs is the geochemistry of gas condensates. The fingerprinting of gas condensates by gas chromatography, in particular, may provide information regarding reservoir compartmentalization, which can be a major uncertainty at the early-field-appraisal stage. An important concern is the capture of suitable liquid samples. When the flowing bottomhole pressure falls below the dewpoint pressure, for example, condensate will drop out near the wellbore and the captured sample may not be representative of the formation fluid.
We conducted two sets of tests simulating the effect(s) of gas-/ liquid-phase fractionation on fingerprinting analyses: (1) at different pressures (all below the dewpoint) at reservoir temperature (RT) region in order to simulate dropout of liquids in the near-wellbore area and (2) to investigate the effect of variations in separator temperature and pressure.
Geochemical fingerprints obtained on our laboratory-fractionated samples show that condensates obtained from gas wells with flowing bottomhole pressures below dewpoint may not be suitable for compartmentalization studies. Differences in separator pressure and temperature affect the fingerprints of gas condensates, but the effects are small and unlikely to alter conclusions regarding potential fluid-flow barriers. We suggest a number of best practices for the collection and analysis of gas condensates for fingerprinting studies.
A Simple Mechanistic Model for Void-Fraction and Pressure-Gradient Prediction in Vertical and Inclined Gas/Liquid Flow
Authors: Khasanov Mars , Khabibullin Rinat , Krasnov Vitaly , Pashali Alexander , Guk Viatcheslav 
Published: March 2009

Summary
A new mechanistic model for two-phase flow in vertical and inclined pipes was proposed on the basis of the drift-flux approach. The proposed model, unlike the other mechanistic models [Ansari et al. (1994); Xiao et al. (1990); Zhang et al.(2003)] that incorporate a system of nonlinear equations to solve, uses an explicit equation for liquid-holdup prediction, thus reducing computation time significantly. Coupled with some simplified assumptions on pressure/volume/temperature (PVT), such a simple form of a liquid-holdup-prediction formula enables an analytical integration of the pressure gradient in two-phase flow along the pipe. This procedure is used usually to speed up the calculation of bottomhole pressure (BHP) for a large number of wells for oil-production-optimization purposes (Khasanov et al. 2006).
The drift-flux approach can predict liquid holdup for bubbly flow quite accurately. However, for slug flow, it usually underestimates the void fraction. Because slug flow is the most common flow in producing wells, this leads to the pressure drop being overestimated significantly; this can be proved by comparing computational results to the experimental data and mechanistic models. Small gas bubbles in liquid slugs should be accounted for when predicting liquid holdup for slug flow more accurately. Gas in the slug body is considered by adding a proper term to the void-fraction expression. This term is based on the correlation for liquid holdup in the slug body. The model was evaluated with Rosneft's field data and the Tulsa University Fluid Flow Projects (TUFFP) databank. The model was evaluated by comparing it with three mechanistic models for multiphase flow.
Predicting Accelerating Subsidence Above the Highly Compacting Luconia Carbonate Reservoirs, Offshore Sarawak Malaysia
Authors: Dudley J. W. , van der Linden A. J. , Mah K. G. 
Published: March 2009

Summary
Sarawak Shell Berhad has a number of offshore gas fields that produce from the Luconia carbonate formation, which can exhibit high-compressibility pore-collapse deformation. Recent accelerated subsidence has been observed at several of these fields, which extrapolates to final subsidence values well above previous estimates. This paper describes a geomechanical study involving core work to determine if the Luconia formation compressibility is sensitive to brine flow from the rising aquifer and a 3D geome-chanical finite-element model developed to predict future subsidence and lateral movements for the F23 platform.
Compaction tests were performed on the Luconia core from three different gas fields. Tests on twin plugs were conducted—one plug undergoing a standard uniaxial zero-lateral-strain compaction test, while its twin has several pore volumes of simulated-formation brine flowed through it (at virgin in-situ stress conditions) before the compaction loading. Four sets of compaction tests on twin plugs were completed. The higher-porosity samples showed characteristic pore-collapse behavior consistent with previous measurements on Luconia mouldic limestone core. No sensitivity to brine flow was observed. In-situ compaction logs in the field also do not show increased compressibility in sections flooded by the rising gas-water contact (GWC). The geomechanical model uses a relatively simple structural model comprised of four layers—two overburden formations, the Luconia carbonate and one underburden formation. A nonlinear deformation model for the Luconia formation captures the accelerating pore-collapse response observed in the core and in-situ compaction measurements. The model is calibrated to GPS-measured platform subsidence and is consistent with measured core- and field-compaction properties. The results predict that platform subsidence rates with depletion would level off, with a maximum subsidence of 18.5 ft +/− 1 ft at an abandonment pressure of 300 psi. Platform subsidence in the two years following the work continues to follow the predicted values.
This work illustrates the importance of integrated geomecha-nical core testing, field-monitoring measurements, and modeling to accurately predict compaction and subsidence effects in highly compacting environments.
Inverted-Convection Proppant Transport for Effective Conformance Fracturing
Authors: dos Santos J. A. C. M. , Cunha R. A. , de Melo R. C. B. , Aboud R. S. , Pedrosa H. A. , Marchi F. A. 
Published: March 2009

Summary
In mature fields, a continuous challenge for operators is to maximize hydrocarbon recovery while minimizing associated water production. Water production causes several problems, including scaling, fines migration or sand-face failure, tubular corrosion, and increased hydrostatic loadings. Thus, although water production is almost an inevitable consequence of oil production, it is usually desirable to defer its onset, or its rise, as long as possible.
Proper stimulation is required to prove many reservoirs commercially, including dirty sandstones and lower-permeability layered formations in waterdrive reservoirs and/or with nearby water zones. The focus on water avoidance has made conformance fracturing an interesting prospect in mature fields because it combines synergistically a relative permeability modifier (RPM) with a fracturing fluid to enhance production and reduce water cut in one step. However, if a water zone is below the zone being fractured, fracture invasion may create a conductive path for water production. For example, proppant convection and settling can result in heavier treatment stages displacing rapidly downward from the perforations to the bottom of the fracture. This may occur when treatments call for large pad volumes, high proppant concentrations, or stage density contrasts.
An important technique used to avoid this problem is known locally as inverted proppant convection. It requires proppant buoyancy in the selected fracturing fluid, as is possible when using ultralightweight proppants (ULWPs) with specific gravities (SG) from 1.054 to 1.75. The technique involves pumping a high-density fluid pad with SG higher than the proppant carrier fluid, which in turn has SG slightly higher than the selected ULWP.
This paper describes the design approach, operational procedures, and evaluation of field case histories demonstrating the synergism of conformance fracture and inverted proppant convection as applied in northeast Brazil, with the potential to impact field-development strategies worldwide.
Predicting Undulating-Well Performance
Authors: Kamkom R. , Zhu D. , Bond A. 
Published: March 2009

Summary
Undulating wells are one of the alternatives to horizontal wells in field developments for extremely low-vertical-permeability formations. Undulating wells offer higher reservoir exposure, and they do not depend on vertical permeability as much as horizontal wells do. This makes an undulating well trajectory sometimes more attractive than horizontal wells.
In this paper, we will present two different approaches to predicting undulating-well performance: (1) an analytical model that uses a segmented vertical-well model with a slanted skin factor to account for the effect of undulation and (2) a more-comprehensive model that evaluates undulating-well performance in a parallelepiped reservoir on the basis of a line-source solution. The analytical model is simple and works well under certain formation- and well-structure conditions. The line-source model is more flexible on permeability assumptions and well location. We compared the results of the two approaches to identify the conditions in which the analytical model can be applied.
Field examples are used in the paper to illustrate optimizing undulating-well performance by the model. The Cosmopolitan field, Cook Inlet Alaska, and the Oooguruk field, North Slope, Alaska, are planned for development with undulating horizontal wells. Both reservoirs are challenged with relatively low permeability, low kV/kH ratios, and moderate-viscosity oil. Undulating horizontal wells are needed to overcome these issues and deliver commercial production rates. The performance model developed in this study demonstrated the additional value of an undulating well over a conventional horizontal well, which provided key support in the well-design and field-development plans.
Sorption-Induced Permeability Change of Coal During Gas-Injection Processes
Authors: Lin W. , Tang G. -Q. , Kovscek A. R. 
Published: March 2009

Summary
Our study has two features. First, laboratory experiments measured the change of the permeability of coal samples as a function of pore pressure and injected-gas composition at constant effective stress. Second, adsorption-solution theory described adsorption equilibria and aided interpretation. The gases tested include pure methane (CH4), nitrogen (N2), and carbon dioxide (CO2), as well as binary mixtures of N2 and CO2 of different compositions. The coal pack was initially dry and free of gas, then saturated by each test gas at a series of increasing pore pressures at a constant effective stress until steady state was reached. Thus, the amount of adsorption varied, while the effective stress was held constant. Results show that, (i) permeability decreases with an increase of pore pressure at fixed injection-gas composition, and, (ii) permeability change is a function of the injected-gas composition. As the concentration of CO2 in the injection gas increases, the permeability of the coal decreases. Pure CO2 leads to the greatest permeability reduction among all the test gases. However, 10 to 20% by mole of N2 helps to preserve permeability significantly. According to the mixed-gas adsorption isotherms, adsorption and the selectivity of a particular gas species on coal surfaces is a function of pressure and the gas composition. Therefore, we conclude that loading coal surfaces with adsorbed gas at constant effective stress causes permeability reduction. Finally, gas adsorption and permeability of coal are correlated, simply to extend the usefulness of study results.
Real-Time Performance Analysis of Water-Injection Wells
Authors: Izgec B. , Kabir C. S. 
Published: March 2009

SummaryThis work presents a complete reformulation of the Hall method involving both pre- and post-breakthrough situations. Two approaches involving both transient and pseudosteady-state methods produced very similar solutions, which were verified with the results of coupled geomechanical/fluid-flow simulations. The new formulations allow tracking the expanding water-bank radius from inception to breakthrough. Pressure of this bank at the water/oil interface is evaluated at every timestep, thereby allowing continuous update of the ‘external pressure’ in Hall's formulation. We show that Hall's formulation is a particular case of the proposed approach. Several simulated and field examples demonstrate the value of reformulated Hall analysis.Because Hall formulation involves an integral, the resultant signature, by nature, is insensitive in revealing clues about subtle changes that may occur during formation fracturing or plugging. We observed that the derivative of the modified-Hall integral, obtained analytically, provides definitive signatures about fracturing or plugging.The new interpretation approach is particularly suitable for projects at the inception of flooding. Mature projects can benefit equally from the new tool. Perhaps the biggest appeal of the proposed tool lies in the green fields where real-time data are readily available.