bluuebunny/crossref_metadata_2025_split huggingface dataset:
Breaking of a Paradigm: The Simultaneous Production of the Gascap and Oil Column
Authors: Billiter Travis C. , Dandona Anil K. 
Published: December 2007

Abstract
The conventional way to produce an oil reservoir that has a gascap is to produce only from the oil column while keeping the gascap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gascap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gascap and oil column. This methodology has application in reservoirs with a low-dip angle, relatively large gascap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. The work also demonstrates that the recovery from the gascap is minimally affected by heterogeneities in the reservoir. This is shown using geostatistical reservoir models. The effect of heterogeneities on oil recovery is also documented.
Integrated Approach to Drilling Fluid Optimisation for Efficient Shale Instability Management
Authors: Tan C. P. , Rahman S. S. , Richards B. G. , Mody F. K. 
Published: December 2007

Abstract
An integrated approach to drilling fluid design and optimisation, in terms of mud weight and chemistry, for efficient shale instability management has been developed in a collaborative project. The key drilling fluid-shale interaction mechanisms included in the state-of-the-art design criteria are mud pressure penetration, chemical potential and swelling-hydrational stress.
Fundamental concepts, processes, models and a range of novel test equipment and procedures for laboratory simulation of the mechanisms were developed. Shale and drilling fluid properties required for the models were determined using a range of analytical and laboratory techniques. The laboratory simulation results for various mud types were used in the refinement and verification of the models. The verified models, which have been integrated in a wellbore stability analysis software, were used to conduct analyses to demonstrate the effects of shale and drilling fluid properties on time-dependent wellbore (in)stability. They highlight the conditions in which the mechanisms are critical and need to be incorporated in the analysis. In addition, the test equipment also provide effective methods of screening drilling fluids (type and formulation) for their capacity to provide the required effective mud support with time for a given shale.
The understanding of the mechanisms of drilling fluid-shale interaction and the development of the capacity to model them enabled the development of drilling fluid design charts. These charts, together with a shale property database and property correlations, provide a pragmatic and effective approach for designing optimal drilling fluids to manage shale instability efficiently. The wellbore stability analysis software and drilling fluid design charts have been used in both drilling fluid program recommendation and back-analysis of field experience. A full-scale field trial of the technology is currently being undertaken in collaboration with an operating company.
A Case Study Using a Reservoir Simulation Model to Determine Fracture Azimuth
Authors: Yao Fei , Zhu Ding 
Published: December 2007

Abstract
The fracture azimuth is an important parameter for well performance after fracturing, especially in pattern water flooding in anisotropic reservoirs. There have been several methods developed to determine the fracture azimuth, but most of them are expensive, and/or have limitations in their applications.
This paper presents a case study of using a reservoir simulation model to determine the fracture azimuth by history-matching the production data from a fractured well. The method is practical and convenient. In this study, a 3D, 3-phase reservoir simulator was used to simulate the performances of hydraulically fractured producing wells in Toskoro field in China. Water flooding had been applied to the field before fracturing. Some producing wells then were fractured to improve their productivities. After fracturing, the water cut increased dramatically in some wells, which was suspected to have been caused by the communication between the fractures and the nearby water injection wells. The fracture azimuth of the wells was determined by matching the production history curves, and the simulation result showed that for the well having extremely high water cuts, the fracture was oriented towards the injection well.
The fracture azimuth was also detected by monitoring microseisms during the fracturing stimulation in four subsequent fracture treatments in the same area. The results confirmed the fracture azimuth obtained from the reservoir simulation model. The fracture azimuth was then used in well pattern design in water flooding and fracturing design in the same area to obtain the maximum benefit from hydraulic fracturing.
Enhanced Coalbed Methane Recovery Using CO2 Injection: Worldwide Resource and CO2 Sequestration Potential
Authors: Stevens Scott H. , Spector Denis , Riemer Pierce 
Published: December 2007

Abstract
Injection of carbon dioxide into deep coal seams has the potential to enhance coalbed methane recovery, while simultaneously sequestering a greenhouse gas. Analysis of production operations from the world's first carbon dioxide-enhanced coalbed methane (CO2-ECBM) pilot, a 4-injector/7-producer pattern in the San Juan Basin, indicates that the process is technically and economically feasible. To date, over 2 Bcf of CO2 has been sequestered with negligible breakthrough. Enhancement of gas production can be as high as 150% over conventional pressure-depletion methods. Dewatering of the reservoir is also improved. ECBM development may be profitable in the San Juan basin at wellhead gas prices above $1.75/Mcf, adding as much as 13 Tcf of additional methane resource potential within this mature basin.
The key reservoir screening criteria for successful application of CO2-ECBM include laterally continuous and permeable coal seams, concentrated seam geometry, and minimal faulting and reservoir compartmentalization. Operational practices for CO2-ECBM recovery are still being refined. Injection wells should be completed unstimulated, while production wells can be cavitated or hydraulically stimulated. CO2 injection should be continuous and concurrent with methane production to prevent lateral water encroachment. Apart from the San Juan basin, many other coal basins have significant CO2-ECBM potential. In the U.S., the Uinta and Raton basins are geologically most favorable, while additional potential exists in the Greater Green River, Appalachian and other coal basins. Coal basins in Australia, Russia, China, India, Indonesia and other countries also have large CO2-ECBM potential. When viewed from a commercial project viewpoint, the total worldwide potential for CO2-ECBM is estimated at approximately 68 Tcf, with about 7.1 billion metric tons of associated CO2 sequestration potential. If viewed purely as a non-commercial CO2 sequestration technology, the worldwide sequestration potential of deep coal seams may be 20 to 50 times greater.
Pore Pressure and Stress Gradient Prediction in Geopressured Formations, South China Sea, PRC
Authors: Wydrinski R. , Ramos G. G. , Weng X. , Payne M. L. 
Published: December 2007

Abstract
One of the challenges in drilling wells in South China Sea, Peoples Republic of China (PRC), is the high-temperature/ high-pressure (HTHP) environment. In HTHP, the range of safe mud-densities fall within a very narrow window between the pore pressure and formation breakdown. Planning the three wells drilled in South China Sea relied on pore pressure and fracture gradient predictions that used seismic and sonic input data for models of compaction and borehole stresses. Pressure and stress gradients can be successfully predicted by quantifying the compaction trends and burial rates of the formations, estimating variance from these trends, and then calculating formation strength and pre-drilling stresses. Abnormal pore pressures were deduced from deviations of sonic velocities from known trends based on seismic integrated travel-time data and wireline sonic data. Rock mechanical elastic properties and strength were estimated and then the equations of elasticity and strength-constrained stresses were applied to determine the onset of shear-failure and formation breakdown. The computed safe mud densities for wellbore elastic stability ranged from 16 to 18 ppg. Because of thermal gradients between the formation and circulating mud, calculated thermal-induced stresses may have drastically lowered the breakdown pressures by as much as 1,000 to 2,000 psi. Mud cooling was not advisable in this case.
Huaibei Coalbed Methane Project, Anhui Province, People's Republic of China
Authors: Derickson J. P. , Horne J. S. , Fisher R. D. , Stevens S. H. 
Published: December 2007

Abstract
In cooperation with China United Coalbed Methane Corporation Ltd. (CUCBM), Texaco China BV (Texaco) is evaluating the Huaibei coal basins in northern Anhui Province for coalbed methane development. Texaco's initial exploration will focus on the Sunan and Nanping synclines where Permian-age coals are known to be within optimum maturity levels. Based on recent test drilling data, gas contents of objective coal seams are also shown to be quite attractive. However, the tectonic history of the Huaibei region presents some concern about the in-situ gas saturation levels in the coals. Even though the region certainly has some challenging technical risks, the initial technical evaluation indicates a promising potential. A multi-well core and test program has been designed to quickly and efficiently evaluate specific reservoir properties prior to critical decisions for pilot testing and full-scale commercial development. Key reservoir properties to be determined include coal thickness, permeability, porosity, gas content and gas saturation levels. Reservoir model studies using a coalbed methane simulator will then be used to examine the productive potential of the area. The variability and sensitivity of these key reservoir parameters in regard to production rates is discussed along with Texaco's exploration and development strategy. The paper also discusses the operational plans and overall strategy of managing risk by utilizing a phased approach.
Drilling a World Record ERW in the South China Sea
Authors: Talkington Brian Kelly , Morgan Dennis R. , Jiang Zhang Ming 
Published: December 2007

Abstract
In 1996, Phillips China, Inc. (PCI) based in Shekou, People's Republic of China, was faced with the decision to either submit a development plan for the Xijiang 24-1 Field in the 15/11 Contract Area of the South China Sea or to relinquish their rights to the field. The remote location of the field and the relative small size of the reservoir made this decision difficult. Several studies conducted over a number of years on various development scenarios indicated that any type of stand alone development, such as a small platform or subsea wells, would be uneconomical. It was, therefore, concluded that the only way of developing the 24-1 was to drill an extended reach well (ERW) from PCI's Xijiang 24-3 Platform, over 8-km away. Such a well would have a world record horizontal reach.
One of the biggest concerns for the success of an ERW was whether the platform rig, which was designed for a 4573-m measured depth (MD) (3049-m true vertical depth (TVD)) development wells, could be upgraded sufficiently. Also of concern were the relatively remote location of the Xijiang operation, the lack of experience in ERW drilling in the area, the transitional step from drilling relatively shallow development wells to drilling a world record ERW, hole stability, torque and drag, directional control, logistics and weather.
This paper will describe the upgrade process performed on the drilling rig to enable it to drill and complete this record breaking well. It will include a post-well evaluation of the upgrades. In addition, it will describe the drilling and completion of the well and how PCI addressed all the concerns listed above.
Edafic and Successional Changes Generated by Drill Wastes Application in Acid-Sulfate Soils at the Upper Orinoco Delta
Authors: Vásquez P. , Urich J. , Rodríguez A. , González V. , Marcano J. , López C. , Colombo P. 
Published: December 2007

Abstract
Since 1995 PDVSA environmental management policies for oil exploration and production activities (E&P), have encouraged significant research in order to safely dispose of drill cuttings (DC) in previously drained and consequently acidified wetland soils from the Orinoco upper Delta, due to the exposure of their underlying pyritic (FeS2) marine clays to more oxigenated environment. These soils with pH &lt;3.5, high exchangeable Al (&gt;15 meq/100g.), and low saturation of exchangeable bases (Ca, Mg), are commonly colonized by Cyperaceae weeds. In a field experiment located nearby Varadero de Manamo (Monagas state), the addition and tillage of DC in concentrations ranging from 200 to 1000 m3/ha, produced total reduction of exchangeable Al, as well as pH increase in the range of 5.6 to 6.9. During two years, floristic and successional changes were evaluated. It was observed a progressive substitution of the non palatable sedge cover by useful cattle and wildlife species (Leersia hexandra, Paspalum conjugatum, Oryza rufipogon, Cassia occidentalis, Cassia tora and Axonopus sp.). Net primary productivity changes in the range of 1.7 to 4.6 times over the control plots were found. Changes in soil chemistry, leaching and foliar accumulation of heavy metals are reported. These results show that drill cuttings are a useful resource in the reclamation of wetlands with acid-sulfate soils and for the improvement of regional biological productivity and diversity.
Get Rid of Greenhouse Gases by Downhole Disposal Guidelines for Acid Gas Injection Wells
Authors: Duncan Grant J. , Hartford Catherine A. 
Published: December 2007

Abstract
This paper describes technical considerations and recommendations for the design and completion of acid gas injection wells. These guidelines are based on acid gas disposal well completion and operating experience in the Jedney field. Initial operating and injection well inspection results are also described.
Waste gas from natural gas sweetening plants often contains high Concentrations of carbon dioxide and hydrogen sulphide. Downhole acid gas disposal schemes minimize environmental impact by reducing the release of carbon dioxide and sulphur compounds to the atmosphere. Challenges in the design and construction of Jedney acid gas injection systems included: equipment selection for high concentrations of sour gas, understanding the phase behaviour of acid gas mixtures, use of both new and existing wellbores, accommodation for future well interventions, and safe troublefree operations.
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Wellman Unit CO2 Flood: Reservoir Pressure Reduction and Flooding the Water/Oil
Authors: Schechter David S. , Grigg Reid , Guo Boyun , Schneider Barry 
Published: December 2007

Abstract
CO2 injection is a proven technology. Results from two decades of reservoir and economic performance prove that CO2 can 1) be transported over large distances via pipeline 2) handled and injected easily at well-site facilities and 3) recover oil that water injection could not mobilize. This has been accomplished at cost levels which are profitable provided enough HCPV (hydrocarbon pore volume) of CO2 is injected in the reservoir and sweep and displacement efficiency are sufficient.
The most recent challenge involves optimizing efficiency of CO2 flooding, i.e. maximizing oil recovery while at the same time reducing operating expenses. A useful method to attain the goal of CO2 flood optimization is careful performance review of better performing CO2 floods. The Wellman Unit CO2 flood has a long history. This CO2 flood is one of the most successful CO2 floods documented in terms of CO2 utilization, i.e. MCF of CO2 required to recover one barrel of oil. This paper explores the role of laboratory experimentation for improvement of performance of a mature CO2 flood.
In this paper, we will review the history of the Wellman Unit CO2 flood and examine two possibilities to optimize reservoir performance:Reducing CO2 injection pressure thereby reducing the volume of purchased CO2 while at the same time maintaining miscibility (optimum displacement efficiency) andExploring the possibility of mobilizing reserves in the water-oil transition zone below the original oil-water contact.
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Identification of Geological Shapes in Reservoir Engineering by History Matching Production Data
Authors: Rahon Daniel , Edoa Paul Francis , Masmoudi Mohamed 
Published: December 2007

Abstract
This paper discusses a method which helps identify the geometry of geological features in an oil reservoir by history matching of production data. Following an initial study on single-phase flow and applied to well tests, the research presented here was conducted in a multi-phase flow context.
This method provides information on:- the limits of a reservoir being explored,–the position and size of faults,–the thickness and dimensions of channels.
The approach consists in matching numerical flow simulation results with production measurements. This is achieved by modifying the geometry of the geological model. The identification of geometric parameters is based on the solution of a inverse problem and boils down to minimizing an objective function integrating the production data.
The minimization algorithm is rendered very efficient by calculating the gradients of the objective function with respect to perturbations of these geometric parameters. This leads to a better characterization of the shape, the dimension and the position of sedimentary bodies.
After describing the optimization process used, several examples are presented in this article, in particular an application of the method in a two phase water-oil case. The geological model used in this study was built using an integrated reservoir characterization tool. This heterogeneous model is composed of several geological units and contains a group of main faults whose positions represent the matching parameters used in the study.
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Prediction of Sand Problems of a Horizontal Well from Sand Production Histories of Perforated Cased Wells
Authors: Morita N. , Fuh G.F. 
Published: December 2007

Abstract
This paper compares numerical model predictions and laboratory data on sand production and borehole stability tests. It also compares numerical model predictions and field data on sand production and borehole stability tests. These comparisons show that model predictions agree with both field and laboratory results for sand production problems; however, for borehole stability problems, the model prediction does not necessarily agree with both laboratory and field results. The laboratory results show strong size effect, and the predicted borehole failure conditions lie between those predicted with the non-linear Mohr Coulomb and the non-linear Drucker-Prager. However, the field borehole is generally more stable than the laboratory results and its failure condition is close to the value predicted by the non-linear Mohr-Coulomb constitutive theory.
Using the field calibrated model predictions, a parametric analysis was conducted on the difference of the well flowing pressure between perforated wells and horizontal openholes. The analysis shows that the well flowing pressure to induce sand production for cased wells are normally lower than that of horizontal wells. The pressure difference mainly depends on the horizontal and axial stress ratio, rock deformation and strength properties.
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Operational Design Considerations for Frac-and-Pack Tools to Reduce Risk
Authors: Smith Jeff , Landry Tim , Wagner Dave 
Published: December 2007

Abstract
The dynamics of tip screen out frac and pack treatments provide challenges for sand control tool operations by creating forces on the sand control tools and the work-string. This paper reviews forces on the sand control tools during a frac and pack and the effects of drag, stretch, and helical buckling on the work-string before and after frac and pack operations. Case studies are presented.
Methods for determining forces on work-strings used in fracture treatments were presented in the early 1960's by Lubinski et al1. Determination of these forces assumed vertical wells. Frac and pack operations are often conducted in deviated wells which create work-string drag and result in pipe stretch or buckling. In-complete analysis of these forces can lead to premature job termination or tool failure. Guidelines are provided for packer - work-string forces, work-string drag, work-string stretch and buckling determination in typical frac and pack operations. Included are empirical data for fracture pressure prediction, work-string temperature change, friction pressure drop, and work-string to casing friction factor values.
Field Results of Separation Vessel and Multiphase Flowline Debottlenecking Using an In-line Gas/Liquid Auger Separator
Authors: Weingarten Jean S. 
Published: December 2007

Abstract
Field results of auger separator installations are presented which demonstrate the following new applications of in-line gas/liquid partial separation:increasing separation vessel capacity (or reducing required vessel size for a given flow rate) andreducing pressure drop in multiphase lines that transport produced hydrocarbons.
The auger separator is a device which partially separates liquid and gas, has no moving parts, and requires no power or level controls. The diameter of the separator is typically a few inches, generally about the same diameter as the line, and is installed as a spool piece in the line.
In one application, a field test was conducted where the auger separator was placed just upstream of a conventional test separator. By removing a portion of the gas upstream, the liquid capacity of the vessel was approximately doubled. In a different application, auger separators were installed to remove gas from multiphase flow lines and provide raw gas lift on the drillsite. By doing this, the amount of gas in the production line was reduced, decreasing the backpressure and increasing the capacity for produced fluids. The operating conditions before and after the installations, equipment descriptions and photos, piping layouts, and operational considerations are included. The design of the auger separators and performance comparisons to predictions from design equations are also discussed.
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