bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Characterization Methodology to Identify Reserve Growth Potential
Authors: Holtz Mark H. , Hamilton Douglas S. 
Published: December 2007

Abstract
The information available for characterizing a reservoir is insufficient to develop a unique model. However, by applying the proper reservoir characterization methodology, a model can be constructed that optimizes and integrates all the data and thus facilitates the identification of reserve growth potential. This methodology contains four steps:determining reservoir architecture,establishing fluid-flow trends,constructing reservoir model, andidentifying reserve growth potential.
The key to determining reservoir architecture is the application of genetic sequence stratigraphy. The reservoir architecture is determined by ascertaining the internal reservoir stratigraphy, defining the stratigraphic unit geometries, interpreting the distribution of depositional environments, and combining stratigraphy with structural character. Establishing fluid-flow trends should be accomplished within the context of the stratigraphy. This step includes determining the initial fluid and rock-fluid properties, generating a production-time-series analysis, analyzing any variation in fluid chemistry, assessing well test data, and determining the direction of injected fluids. The third and pivotal step of constructing a reservoir model by integrating reservoir architecture and fluid-flow trends has four steps. It begins with designing geologically based petrophysical models, then concurrently identifying the correspondence between reservoir architecture and fluid-flow trends, then establishing the reservoir model flow unit and compartment components. Next, the petrophysical properties are distributed spatially and the hydrocarbons in place are calculated. The final step is identifying reserve growth potential. It is accomplished by calculating reserves, delineating the remaining hydrocarbon resource, generating reserve growth concepts, and targeting reserve growth opportunities.
P. 473
Introducing Imbibition Capillary Pressure in the Assessment of the Smoerbukk and Smoerbukk South Fields Offshore Norway
Authors: Ingsoy P.B. , Skjaeveland S.M. , Hjelmaas T. , Haga O.M. 
Published: December 2007

Abstract
Focusing on the Smoerbukk (Smorbukk) fields it is proposed to introduce imbibition capillary pressure by a new method which entails representing Pc analytically starting from the primary drainage curve. Predicted saturation is shown to agree with wireline log data from a Smoerbukk South well were the initial distribution of saturation was likely established by an imbibition process. Numerical simulation shows that introducing imbibition capillary pressure siguificantly reduced predicted water cut in downflanks producers as compared to simulations presuming no capillary transition zone. This allowed repositioning the producers closer to the oil-water contact, thereby increasing recovery.
Finally, it is demonstrated that numerical simulation efficiency improved by introducing imbibition capillary pressure.
P. 277
The Chronology of Water-Oil Handling Equipment
Authors: Delgado Alberto , Lee H.M. 
Published: December 2007

Abstract
The design of offshore oil-production facilities has evolved throughout the years to cope with increasingly stringent environmental regulations on oily-water discharge. This paper presents the development of technology that oil-producing companies use to clean the produced water associated with crude oil. The early practices for water treatment, the evolution throughout the years of the various treatment approaches, and the prevailing design specifications are reviewed in this paper. State-of-the-art technology, latest design practices, and current industry theories are also presented in this paper, as well as alternate oily-water disposal approaches, latest design practices, and the current approach used to estimate the viscosity of water-oil emulsions, which is a critical design transport parameter.
P. 317
An Integrated Investigation for Design of a CO2 Pilot in the Naturally Fractured Spraberry Trend Area, West Texas
Authors: Schechter David S. , Guo Boyun 
Published: December 2007

Abstract
Designing gas injection projects in naturally fractured reservoirs requires special considerations which, in turn, relies on knowledge of the fracture network. Characterization of the fracture network involves delineation of important physical characteristics, such as fracture spacing, fracture orientation, fracture conductivity (of both natural and hydraulically induced fractures). Of equal significance is understanding the transfer mechanisms between oil and gas in the rock matrix and injected water and gas present in the fracture network.
Integration of fracture characterization with results obtained during experimental investigation of transfer mechanisms is a key step for history matching and predicting reservoir response to water or gas injection. This paper describes the steps taken in two important areas of 1) fracture characterization and 2) fluid exchange from fracture to matrix as a precursor for design of a 10 acre CO2 pilot in the naturally fractured Spraberry Trend Area.
Fracture and matrix characterization are based on oriented vertical and horizontal core taken from Upper Spraberry reservoirs. Fluid exchange mechanisms are investigated in reservoir plugs and whole core at reservoir temperatures and pressures. Results of imbibition/wettability and CO2 gravity drainage experiments are presented. History matching Spraberry waterflood performance and predicting performance. under CO2 injection is presented based on integration of reservoir characterization and laboratory experimentation.
P. 325
Review of WAG Field Experience
Authors: Christensen J.R. , Stenby E.H. , Skauge A. 
Published: December 2007

Abstract
In recent years there has been an increasing interest in water-alternating-gas (WAG) processes, both miscible and immiscible. WAG injection is an oil recovery method initially aimed to improve sweep efficiency during gas injection. In some recent applications produced hydrocarbon gas has been re-injected in water injection wells with the aim of improving oil recovery and pressure maintenance. Oil recovery by WAG has been attributed to contact of unswept zones, especially recovery of attic or cellar oil by exploiting the segregation of gas to the top or accumulating of water towards the bottom. Since the residual oil after gas flooding is normally lower than the residual oil after water flooding, and three-phase zones may obtain lower remaining oil saturation, water- alternating-gas has potential for increased microscopic displacement efficiency. WAG injection, thus, can lead to improved oil recovery by combining better mobility control and contacting unswept zones, and also leading to improved microscopical displacement.
This study is a review of the WAG field experience as it is found in the literature today from the first reported WAG in 1957 in Canada and up to new experience from the North Sea. About 60 fields have been reviewed. Both onshore and offshore projects have been included, as well as WAG with hydrocarbon or non-hydrocarbon gases. Wellspacing is very different from onshore projects (where fine patterns often are applied) to offshore projects (well spacing in the order of 1000 meters).
For the fields reviewed, a common trend for the successful injections is an increased oil recovery in the range of 5-10 per cent of the OIIP. Very few field trials have been reported as unsuccessful, but operational problems are often commented. Though, the injectivity and production problems are generally not detrimental for the WAG process, special attention has been given to breakthrough of injected phases (water or gas). Improved oil recovery by WAG is discussed as influenced by rock type, injection strategy, miscible/immiscible gas, and well spacing.
P. 357
Controlled Viscosity Reduction and Increased Fracture Conductivity Using a High-Temperature Breaker System
Authors: Dusterhoft R. , Parker M , McCabe M , Schubarth S. 
Published: December 2007

Abstract
High-temperature fracturing-fluid breaker systems have been used in fracturing operations for the past several years. The advantage of using these systems has been improved fracture conductivity, but there has been an increased risk of poor proppant placement and premature screenouts resulting from early viscosity reductions as the fluid is exposed to high temperatures. In many cases, this problem could only be avoided by adding breaker to the final portion of the proppant stages, essentially improving the fracture conductivity in the near wellbore region without enhancing the conductivity of most of the proppant pack.
This paper highlights innovative research for developing high-temperature breakers that work synergistically with gel stabilizers to maintain excellent gel viscosity. This viscosity allows sufficient time to place the treatment while still providing a more complete break and improved fracture conductivity. Laboratory testing has shown that this high-temperature breaker system can be used effectively at temperatures as high as 350 F without sacrificing early-time fluid viscosity or proppant placement, while still providing dramatic improvements in fracture conductivity.
Field production has been analyzed and shows the combined benefits of improved proppant placement and increased fracture conductivities obtained with the application of this technology.
P. 409
Gulf of Mexico Frac-and-Pack Treatments Using a New Fracturing Fluid System
Authors: Powell R. J. , McCabe M. A. , Slabaugh B. F. , Terracina J. M. , McPike T. 
Published: December 2007

Abstract
Borate-crosslinked fracturing fluids have been among the fluid choices in the early growth of the frac-and-pack treatments in the Gulf of Mexico.1 Highly conductive fractures connecting the wellbore and formation were recognized as key to the success of frac-and-pack treatments.2 To enhance fracture conductivity, one suggestion was minimizing polymer loading and maximizing breaker loadings to a point that does not adversely affect fluid stability during the frac-and pack-treatment.3
All three of these elements have been combined in a new fracturing fluid system for fracturing and packing treatments. This new fluid system provides higher viscosity with lower gelling-agent concentrations than conventional, borate-crosslinked fluids. A new, non-persulfate breaker system has been developed for use with this fluid system specifically for use from 170° to 200°F.
The new, optimized borate-crosslinked fluid system (OLGB), with application to 200°F, was applied to frac-and-pack treatments in the Gulf of Mexico. This paper provides laboratory data and examplesdiscusses the field application of the new fracturing fluid systemcompares the new OLGB fluid system to existing conventional borate fluidsdiscusses the newly-developed breaker systempresents viscosity, fluid-loss, and conductivity data for the new system.
Application of PEP/IMP Transitory Criteria for the Assessment of Fixed Offshore Platforms in the Bay of Campeche
Authors: Rey L.E. , Bayazitoglu Y.O. , Valdes V.M. 
Published: December 2007

Abstract
This paper summarizes the application of the PEP/IMP Transitory Criteria for the assessment of fixed offshore platforms located in the Bay of Campeche, Mexico. Comparisons of the Transitory Criteria with the Section 17 of API-RP2A, 20th edition are made, utilizing two sets of metocean data. Design level analysis and ultimate strength analysis results and comparisons are presented, which included the application of the Load Reduction Factors (LRF's) and calculation of the Reserve Strength Ratios (RSR's). Also, seismic assessment procedures, results and comparisons are summarized. The results of the analyses using metocean and seismic loadings were used to determine the fitness-for-purpose adequacy of 14 PEMEX platforms located in the Southwest Marine Region of the Bay of Campeche.
P. 433
Stress Dependent Permeability in Low Permeability Gas Reservoirs: Travis Peak Formation, East Texas
Authors: Davies John P. , Holditch Stephen A. 
Published: December 2007

Abstract
This paper identifies factors that control stress dependent permeability in tight gas sandstones of the Travis Peak formation in East Texas, and presents a procedure for prediction of in-situ permeability at any value of net effective stress. Petrophysical analysis of core samples reveals that potential reservoir sandstones can be divided into 3 Rock Types; intervals of rock characterized by a unique response of permeability to stress. The rate of permeability decline with increasing net effective stress is different for each Rock Type and is controlled by three interrelated, pore geometrical parameters -- length, shape and short axis dimension of the pore throats. In these sandstones, permeability reduction is not controlled by the amount of porosity, shale volume, grain size, and volume of authigenic cements (silica, carbonate, and clay). Fundamental controls on pore throat size and shape are grain packing (nature of grain-to-grain contacts) and pore type (primary versus dissolution pores). Rock Type based equations are presented that allow for prediction of permeability and the amount of permeability loss for any value of reservoir stress.
The Rock Types can be identified using either laboratory measurement of permeability in core samples at different values of stress, or thin sections of rock samples, including cutting fragments. Algorithms are developed that allow for wireline log identification of each Rock Type using a basic set of log responses (Gamma Ray, Resistivity, Density/Neutron). A knowledge of Rock Type and porosity from wireline logs allows for prediction of permeability at any value of stress through zones of interest in non-cored wells.
Successful Application of Advanced Stimulation Technologies: A Multi-Field Case History
Authors: Caron J.D. , Froebel K.A. , Montgomery R.V. , Periman J.D. , Turner T.J. , Dunn K.P. 
Published: December 2007

Abstract
In early 1996, the Houston Division of Fina Oil & Chemical Company became involved in the Gas Research Institute's (GRI) Advanced Stimulation Technology (AST) Deployment Program through S. A. Holditch and Associates, Inc. During their involvement in the AST program (1996), Fina's Houston Division engineers were responsible for approximately 70 fracture treatments involving roughly 12,000,000 lb of proppant. The use of Advanced Stimulation Technologies on each treatment has provided multiple benefits:
- 5-25% increase in cumulative gas production (0.25-0.5 BCF/well) due to improved fracture treatment effectiveness,
- incremental 10 year NPV (10% discount factor) of $ 15 million and
- tangible cost savings of approximately $750,000 through a reduction in premature screen-outs and in treatment optimization.
Fina continued to utilize these advanced technologies in 1997, applying them to over 54 treatments involving approximately 11,650,000 lb. of proppant. This paper discusses the AST methodology and the successful implementation of these technologies in fracture stimulation programs performed in a variety of producing horizons in multiple fields throughout Louisiana, east Texas, and south Texas.
P. 407
Methods of Neuro-Simulation for Field Development
Authors: Doraisamy H. 
Published: December 2007

Abstract
This paper introduces a methodology for optimizing field development schemes. The use of numerical simulation models in establishing field development strategies is a widely practiced approach. In field development studies, a large number of scenarios which result in a time consuming and expensive process must be considered. The objective of this paper is to structure the field development schemes using artificial neural networks (ANNs) in conjunction with numerical reservoir simulation; a process we call neurosimulation. In neuro-simulation, a few field development scenarios are examined using a numerical simulator. The results of these studies are then used to train the ANN. The trained ANN is used as a predictive tool for field development purposes. Using neuro-simulation, the number of numerical simulations is significantly reduced. The use of the neuro-simulation approach becomes practical especially during the early life of the field when the recovery data and the field properties are sparse and sporadic. The neurosimulation approach provides the flexibility of considering any location as a potential site in contrast to the conventional simulation approach when the well locations are restricted to the pre-defined block centers. The neuro-simulation approach is faster and more efficient than its conventional counterpart. The results obtained from neuro-simulation compare well with the results obtained from a reservoir simulator.
Refork Completion Analysis with the Aid of Artificial Neural Networks
Authors: Shelley Robert F. , Stephenson Stan , Haley Will , Craig Ed 
Published: December 2007

Abstract
The quality and quantity of information available in the public domain is growing rapidly. Companies are creating in-house databases to track and improve operating and service performances in an effort to keep up with this explosion of data. The hardware and software used to obtain and manipulate massive amounts of information are constantly improving. All these events have created an opportunity to evaluate the complex interaction of variables and quantify how they relate to the required end result.
The Redfork formation is a prolific, low-permeability, natural gas and gas-condensate reservoir deposited during the middle Pennsylvanian Period. The reservoir is located in the deep Anadarko basin of west-central Oklahoma. The Redfork is an interesting reservoir because of its high level of heterogeneity and the varied stimulation/completion methods used in the formation. The volume and diversity of information available on Redfork completions make the Redfork formation unique.
This paper analyzes Redfork completions in Roger Mills and Custer Counties. The study uses artificial neural networks (ANNs) trained on a data set of 107 Redfork completions to analyze and quantify the effect of well/reservoir parameters and completion methods on production results. Specific areas of interest include controllable/quantifiable aspects of a well's completion/stimulation procedure that affect the production outcome. The paper will document a methodological test that supplements standard completion-optimization techniques.
P. 555
A New Pressure Transient Well Testing Method for Gas Condensate Wells
Authors: Jatmiko W. , Daltaban T.S. 
Published: December 2007

Abstract
One of the most important parameters for analysing wellbore pressure response in gas condensate reservoirs is the pseudopressure function. This function correlates the reservoir pressure and saturation distributions, and hence the non-linear governing equation can be transformed into a linear equation and solved using a standard method.
This paper describes a method of analysing wellbore pressure response of a gas condensate reservoir under transient conditions. In this study, the pressure distributions are calculated using iterative line source approximation and superposition principles. Initially, the steady-state saturation is assumed. The reservoir saturation distributions are estimated from the sandface saturation and the two-phase flow radius using a quadratic equation. The pseudopressure function is then calculated based on these distributions. The pressure distribution is then recalculated based on this saturation distribution. The material balance method is used to verity the saturation distributions. The dimensionless wellbore pseudopressure is calculated from the wellbore pressure data and compared with the dimensionless pressure (liquid solution).
In general the proposed method shows a good agreement with the liquid solution during transient conditions and hence it can be used to estimate the transport properties of gas condensate reservoirs.
P. 97
Effect of High Velocity on Pressure Transient Analysis of Multilayered Gas Reservoirs
Authors: Gomes E. , Reza Z.A. 
Published: December 2007

Abstract
Worldwide increased demand for natural gas has challenged researchers to come up with more accurate reservoir description and reserve estimation for natural gas. This study uses a semi-analytical model to study pressure transient behavior of multilayered gas reservoirs. Gas flow though porous media is complicated by pressure dependent fluid properties, reservoir heterogeneities, high velocity effect, etc. High velocity effect causes additional pressure drop at the wellbore which is a function of flow rate, fluid and/or rock properties very close to the wellbore. As a result of drilling, rock properties, such as porosity and permeability, in the vicinity of the wellbore are affected. Moreover, large pressure gradient very close to the wellbore causes pressure dependent gas properties vary in the radial direction. Using a semi- analytical model this paper studies transient gas flow behavior through a multilayered reservoir. Both crossflow and commingled layer situations have been considered. In this study, different schemes for calculating high velocity effects have been studied and evaluated. For the same amount of skin, both thin skin and finite damaged zone responses have been compared, It has been observed that for the same amount of skin, finite damaged zone and thin skin responses can be significantly different for gas reservoirs. Effect of permeability, layering, and different outer boundary conditions have also been studied.
P. 111
New Shape Factors for Wells Produced at Constant Pressure
Authors: Helmy M.W. , Wattenbarger R.A. 
Published: December 2007

Abstract
New shape factors are developed for bounded reservoirs produced by wells operating at constant bottomhole pressure. The new shape factors should replace Dietz shape factors (constant rate shape factors) when calculating the productivity of wells producing at constant bottomhole pressure; thus obtain a more reliable long term production forecast. Although the constant pressure and constant rate shape factors are conceptually different, they are close in value for regular shapes (square) with well in the center. However, for irregular shapes and off-centered wells, the difference is significant. The use of constant rate shape factors for predicting the performance of wells producing at constant bottomhole pressure results in over-estimation of well productivity.
P. 131
Effect of Heterogeneity on the Non-Darcy Flow Coefficient
Authors: Narayanaswamy Ganesh , Sharma Mukul M. , Pope Gary A. 
Published: December 2007

Abstract
An analytical method for calculating an effective non-Darcy flow coefficient for a heterogeneous formation is presented. The method presented here can be used to calculate an effective non-Darcy flow coefficient for heterogeneous gridblocks in reservoir simulators. Based on this method, it is shown that the non-Darcy flow coefficient of a heterogeneous formation is larger than the non-Darcy flow coefficient of an equivalent homogenous formation. This result is confirmed using numerical simulations. Non-Darcy flow coefficients calculated from analysis of well test data from a gas condensate field show that non-Darcy flow obtained from well tests that are significantly larger than those predicted from experimental correlations. Permeability heterogeneity is, therefore, a very likely reason for differences in non-Darcy flow coefficients often seen between lab and field data.
P. 215