bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Single Trip Horizontal Gravel Pack and Selective Stimulation System Improves Injectivity in Deepwater Wells
Authors: Vilela Alvaro , Calderon Agostinho , Padilha Gesus , Germino Mario 
Published: December 2007

Abstract
Conventional horizontal gravel pack completions typically require multiple trips. Disadvantages of the conventional system may include the loss of rig time due to multiple trips and repeated rig-up / rig-down of pumping equipment, formation damage due to completion fluid losses and fluid loss pills, and incomplete filtercake cleanup across the entire gravel packed interval. A novel single trip horizontal gravel pack and selective stimulation (SHGPSS) system has been developed and implemented. This system allows the gravel pack assembly to be installed, the gravel pack to be pumped, and selective stimulation of the entire packed interval to be performed – all in a single trip. The benefits of the SHGPSS system include valuable rig-time savings and, efficient mechanical diversion of the stimulation fluid.
This paper outlines the first applications of the SHGPSS system to successfully complete five deepwater horizontal injection wells in the Campos Basin, offshore Brazil. Hydrostatic pressure was maintained on the formation during all treatment phases, thus preventing any underbalance that could lift the filtercake off the formation and cause undesirable fluid losses. After gravel packing, a secondary ball was dropped opening a bypass area and converting the gravel pack tool to a selective stimulation tool. The system then provided the ability to perform a filter cake cleanup and stimulation by selectively treating the horizontal interval 40 ft to 80 ft at the time, depending on the screen joint length.
Economic considerations along with completion efficiencies are especially important on deepwater, subsea completions. The novel SHGPSS system can reduce rig-time generating significant cost savings. Exceptional mechanical diversion of the stimulation fluid allows effective filtercake and formation damage removal yielding efficient completions. Case history information on five subsea, offshore Brazil, deepwater wells will further detail the optimized completions accomplished utilizing the SHGPSS technology.
Optimization of Frac/Pack Completions Based on Field Experience
Authors: Morales R. H. , Profinet J. , Piedras J. , Gadiyar B. , Harris S. 
Published: December 2007

AbstractAs the frac/pack technology continues to evolve, there are a number of topics that need more understanding and improvement. Some of these are: The estimation of correct closure pressure, which in turn leads to evaluation of the correct fluid efficiency, and ultimately leads to the design of the slurry schedule. In addition, a proper fluid selection criterion is critical to the placement of highly conductive propped fracture wings via tip screenout.This paper describes the long strides that have been taken to address these areas. Special attention is given to skin data from build-up tests showing skin increasing with increase in kh. In essence the paper shows effective ways to lower the skin, and consequently increase production. This goal is accomplished by adjusting the design of the frac/pack slurry schedule to observation from field data and to numerical modeling of the fracturing process, and also, by considering the issues stated above. As a consequence, the paper shows that important steps to minimize the skin are to: Design the fracturing fluids to suit the character of the fractures in soft formations where cooldown, fluid velocities, and fluid exposure time are important.Use equilibrium method to fine-tune the closure pressure (and fluid efficiency) evaluation.Clean and pack the perforations not aligned with the fracture.Use diversion techniques to pack the entire reservoir.Evaluate the packing efficiency with bottomhole gauge data (temperature and pressure) and/or radioactive tracers.When these steps are meticulously followed, fracture performances with lower skins can be obtained as demonstrated in the case history.
Cost-Effective Multidisciplinary Approach to Well Planning and Drilling of a Shallow Water Flow Using Real-Time Monitoring Avoidance in a Gulf of Mexico Deepwater Well
Authors: Citta F. , Russell C. , Greenwood J. A. , Williamson S. 
Published: December 2007

Abstract
This paper will demonstrate the planning steps and benefits realized by an operator through the creation of a multidisciplinary planning team. By evaluating a high-risk zone using their own and third party expertise and the involvement of service company optimization engineers at the planning and drilling phases, significant cost savings were achieved.
Integration of the predrill planning process and offshore real-time monitoring service led to the successful drilling and containment of a shallow water flow (SWF) in the Green Canyon area of the Gulf of Mexico. A detailed shallow geohazards assessment for the proposed exploratory well location was performed. The assessment was based on seismic interpretation of a 2-D, high-resolution hazard survey and on a conventional 3-D seismic data integrated with offset well information.
To improve the likelihood of detecting the SWF during drilling — in addition to Gamma, Resistivity and annular Pressure Whilst Drilling (PWD) measurements — a Logging While Drilling (LWD) acoustic tool capable of deriving acoustic delta t in the larger top-hole section was employed: the first time this had ever been attempted. This employment also allowed the sonic and resistivity normal compaction trend to be established before the onset of any overpressure, a benefit both in SWF detection and for overpressure analysis in deeper sections of the well.
The decision was made to drill 30-in. and 24-in. hole sections with sea water until a SWF was encountered and then use weighted mud to stop the influx as rapidly as possible. A SWF casing and cementing program was implemented once the required section TD was attained.
Transmission of real-time data to wellsite and office locations assisted the entire drilling team to function effectively as a unit and also reduced the response times to critical events.
In Search of an Optimal Parameterization : An Innovative Approach to Reservoir Data Integration
Authors: Schaaf T. , Mezghani M. , Chavent G. 
Published: December 2007

Abstract
History matching, by nature, is an ill-posed inverse problem that can be computationaly intensive and practically infeasible for multi-million cells reservoir models. Therefore, the search of an optimal parameterization is of crucial interest to get a fast history matching procedure. One has to find the number of degrees of freedom of a given problem while avoiding the pitfall of overparameterization. Many techniques (such as singular value decomposition) allow to tackle this problem but the main limitation in reservoir engineering is coming from computational-speed issues.
Using gradient-based optimization techniques, we propose here a complemetary approach which uses the power of adjoint state method to select the degrees of freedom which are significant for the objective function. Data integration may be performed by using the gradual deformation method (GDM) for the geological model parameterization : coefficients of a linear combination of geostatistical realizations are modified as the optimization process goes on. The parameterization is then reduced to the coefficients of the linear combination whatever the size of the geostatistical realizations. Working in a stochastic framework, there is initially an infinity of realizations to choose from. Following the new approach, we are able to compute a priori "refinement indicators" that indicate us which degrees of freedom (i.e. realizations) might improve the iterative reservoir model in a significant way. Using only those useful degrees of freedom, we are able to get a better and faster optimization problem resolution. The use of "refinement indicators" will allow us to reduce to one or even zero the number of randomly picked initial geostatistical realizations.
We applied this methodology to integrate interference test data into 3D geostatistical models (both lognormal and facies-based permeability distributions) containing about two millions cells. This validation highlights the capability of the methodology to speed up the inverse problem resolution by selecting optimal geostatistical realizations from a given set.
Sensitivity Study of Flow Unit Definition by Use of Reservoir Simulation
Authors: Stolz Anne-Kristine , Graves Ramona M. 
Published: December 2007

Abstract
The concept of flow units has been developed to integrate geological and petroleum engineering data. A flow unit is defined as a group of reservoir rocks with similar properties that affect fluid flow.
Different methods can be applied for the definition of flow units and their corresponding petrophysical properties. The amount of information required by each method varies depending on the data and the tools available. This leads to different flow unit interpretation of the same reservoir. The objective of this study is to compare seven methods for flow unit definition to a known answer using numerical simulation to predict the flow performance of the reservoir.
The data set corresponds to the research well CSM Strat Test #61, which is located near Dad, Wyoming, and belongs to the Lewis Shale of the Greater Green River Basin. Conventional and specialized well log information is available for the 1700-ft deep well, in addition to petrophysical measurements on approximately 170 selected core plug samples taken from 600 ft of core. The data for the well includes: gamma ray log, bulk density log, caliper, sonic log, compensated neutron log, nuclear magnetic resonance, air permeability (Klinkenberg-corrected), helium core porosity, minipermeameter readings, capillary pressure analysis, and neural network synthetic permeability.
A simple simulation model is developed using the software ECLIPSE 100, Black Oil. Fluid properties, dimensions of the reservoir, grid size, pressure and production data are the same for all the runs. A waterflood of an oil-water system is simulated as a means of best observing how flow unit delineation affects the results. The results of the reservoir simulation indicate that predicting flow performance varies depending on the flow unit model used. The flow performance is a strong function of the average permeability, and therefore of the flow unit definition method used.
Interpretation of flow units based on petrophysical properties, logs, and stratigraphy are routinely done for characterization of a reservoir. Unless numerical simulation is carried out to confirm the flow unit assignment, errors occur. The use of erroneous flow models leads to incorrect prediction of flow performance in the reservoir.
Subsidence and Horizontal Movement Maps for Application of Reservoir Characterization
Authors: Morita Nobuo 
Published: December 2007

Abstract
Normally, the inverse problem to map reservoir compaction from surface subsidence is an ill-conditioned system since the subsidence bowl gradually changes its curvature, hence, the boundary of pressure depleted area cannot be clearly identified from subsidence bowl. However, the analysis in this paper shows that the peak of lateral surface movement approximately coincides with the pressure depleted peripheral so that if both subsidence and lateral movement maps are constructed, the approximate shape of the pressure depleted area and the lateral distribution of reservoir compaction can be identified. These two maps may be used as it is as a diagnosis tool to identify the location of sealed fault, extent of reservoir section and non-recovered hydrocarbon section.
Imaging the reservoir compaction is further improved if a proper inverse method is applied with the subsidence and surface displacement maps as input data. This paper suggests, for inverse problems with real field conditions where reservoir compaction and elastic moduli are both unknown, to lump multiple layers into a few layers with equivalent anisotropic Young's modulis and to inversely calculate the reservoir compaction and the lumped anisotropic elastic moduli. The resolution and fluctuation of seek parameters are effectively adjusted by the Potter's error covarianace off-diagonal elements. The inverted compaction map shows, more clearly than the original surface displacement maps, the location of sealed fault, extent of reservoir section and non-recovered hydrocarbon section even for relatively deep reservoirs.
Optimal Well Placement in Heterogeneous Reservoirs Via Semi-Analytic Modeling
Authors: Hazlett R. D. , Babu D. K. 
Published: December 2007

Abstract
The need for accurate well productivity models with arbitrary well trajectories spurred a revival in analytic solution methodology for fluid transport problems. Analytic formulations often depict single phase flow throughout the reservoir. The Babu-Odeh horizontal well solution for a box-shaped reservoir with spatially invariant properties is generalized here to allow closed-form solutions for heterogeneous media. A reservoir is decomposed into interacting regions, each with its own reservoir properties and associated analytic potential flow solution. Using well-established boundary element techniques, pressure and flux continuity are imposed at selected interface points to solve for the steady material exchange between regions. Constant pressure and zero flux features (fractures and barriers) are easily entertained at region boundaries. The 2-D, pseudo-steady state solution for heterogeneous media is embedded within a reservoir performance feedback loop of a powerful gradient search method to produce a robust optimal in-fill well placement algorithm. Utilizing this approach, new criteria are developed concerning optimal placement of vertical wells for primary production with respect to heterogeneity, asymmetry, and anisotropy. The semi-analytic method has been extended to 3-dimensional flows to serve as a compute engine for a new generation of reservoir management and optimization tools.
Reservoir Characterization and Infill Drilling Study of a Low-Permeability Carbonate: An Evaluation of Blanket Versus Targeted Infill Drilling Strategies
Authors: Rushing J. A. , Blasingame T. A. 
Published: December 2007

Abstract
This paper presents the methodology and results of a reservoir characterization study of Clear Fork carbonates in the TXL South Unit Field located in Ector County, Texas. The principal objective of our study was to evaluate a targeted infill drilling strategy for future field development. Our study incorporated an integrated approach for which the primary evaluation tool was decline type curve analysis of well production data. The well performance analysis was both supplemented and complemented with petrophysical and geological studies, each representing different reservoir scales. On the basis of our study, we identified areas of the field with the highest reservoir quality and largest oil-in-place volume, thus identifying the areas of the field best suited for infill drilling.
Bringing Al Huwaisah's Volume to Value
Authors: Mijnssen F. C. J. , Davies A. H. , Grondin K. , Keating John , Hsu C. F. , Amthor J. 
Published: December 2007

Abstract
The billion barrel Al Huwaisah Field is located in Northwest Oman and produces from heterogeneous rudist-dominated limestones of the Aptian Shuaiba Formation. It was discovered in 1969 and has been on-stream since 1971. Production peaked at ca. 44,000 bbl/d in 1973 after which production declined to ca. 19,000 bbl/d. Recently, production rates have increased to ca. 28,000 bbl/d, but field-wide recovery factor is still only 18% indicating that potentially large scope volumes remain in the field.
In 2000, an integrated review of the Al Huwaisah field indicated a number of opportunities to mature these large scope volumes. It was noted that key to maturing these opportunities was an improved understanding of the highly complex reservoir architecture, especially regarding the distribution of fractures. Subsequently, a comprehensive fracture study was executed that included both geological information and production data. This study resulted in an improved understanding of the water movements in the field explaining the highly variable first-year net oil rates (0 – 2,500 bbl/d) of the Al Huwaisah wells.
The results of the fracture study were incorporated in newly created static and dynamic models that also took into account the small-scale sedimentological heterogeneities of the Al Huwaisah reef deposits. These models were used together with the historic production review to identify production optimization opportunities, like barefoot completion strategies and water shut-off using expandable tubulars. A few of these opportunities have been implemented so far, resulting in sometimes more than 50 % increase in net oil production for the targeted wells. The barefoot completion strategy has resulted in a 10 % cost saving per well. In addition, well planning using seismic amplitude information was tested, which resulted in more than doubling the initial net production in several wells compared to the average initial well rates in Al Huwaisah.
In identifying the most optimal long-term development strategy for the Al Huwaisah field, the subsurface models are being used to test the benefits of introducing water injection and miscible gas flooding. Based on the model data, a limited water injection field trial is ongoing which resulted in a ca. 20% increase in net oil production for the pilot area. Opportunities for implementing a miscible gas trial are currently being evaluated.
Determination of OGIP for Wells in Pseudosteady-State-Old Techniques, New Approaches
Authors: Ibrahim M. , Wattenbarger Robert A. , Helmy W. 
Published: December 2007

Abstract
In this paper, we investigate the shortcomings of available methods for the analysis of gas well production performance and we propose a new method to more accurately estimate original gas-in-place (OGIP).
Several methods are available in the industry to analyze the production performance of gas wells. The most accurate and dependable of them uses superposition time. This method has the advantage of being able to analyze variable-rate and variable-pressure data, which is usually the nature of field data. However, this method has its shortcomings.
In this paper, we use simulation and field cases to review and compare the application of superposition method and illustrate its shortcomings. We present a new normalized pseudotime plotting function for use in the superposition method to smooth field data and more accurately calculate OGIP. The use of this normalized pseudotime is particularly important in the analysis of highly depleted reservoirs with high compressibility where the superposition errors are largest.
We also present a new tangent method to calculate the OGIP with current reservoir properties for both constant rate and pwf production
Decline Curve Analysis Using Type Curves — Fractured Wells
Authors: Pratikno H. , Rushing J. A. , Blasingame T. A. 
Published: December 2007

Abstract
This work provides the development, validation, and application of new decline type curves for a well with a finite conductivity vertical fracture centered in a bounded, circular reservoir. This work fills a significant void in the modern inventory of decline type curves. In particular, this work is directly applicable to production data analysis for cases taken from low permeability gas reservoirs.
Using an appropriate analytical solution for this case, we prepared "decline" type curves for FcD values from 0.1 to 1000 -individual type curves are generated for each FcD value using a range of reD values from 2 to 1000. The following "type curves" are provided: "Fetkovich" format rate-time decline type curves (constant pressure case): qDd versus tDd"Fetkovich-McCray" format rate-time decline type curves (equivalent constant rate case): qDd versus tDd"Fetkovich-McCray" format rate-cumulative decline type curves: qDd versus NpDd
We provide an example demonstration of the methodology for decline type curve analysis using a field case of continuously measured production rate and surface pressure data obtained from a low permeability gas reservoir.
These solutions/type curves provide an analysis/interpretation mechanism that has not previously been available in the petroleum literature. Compared to field data, we find that the traditional type curve solutions for an infinite conductivity vertical fracture are typically inadequate — and, the new solutions for a well with a finite conductivity vertical fracture clearly show much more representative behavior. This validation suggests that the proposed type curves will have broad utility in the petroleum literature — particularly for applications in low permeability gas reservoirs.
Analytic Wellbore Temperature Model for Transient Gas-Well Testing
Authors: Hasan A. R. , Kabir C. S. , Lin D. 
Published: December 2007

Abstract
Questions arise whether bottomhole pressures (BHP), derived from their wellhead counterpart (WHP), lend themselves for transient analysis. That is because considerable heat exchange may affect the wellbore density profile, thereby making the WHP translation a non-trivial exercise. In other words, gas density is dependent on both spatial locations in the wellbore and time during transient testing. Fully coupled wellbore/reservoir simulators are available to tackle this situation. However, they are not readily adaptable for their numeric formulations.
This paper presents analytic expressions, derived from first principles, for computing time-dependent fluid temperature at any point in the wellbore during both drawdown and buildup testing. The simplicity of the analytic expressions for Tf (z, t) is profound in that one can compute flowing or shut-in BHP's on a spreadsheet.
Two tests were considered to verify the new analytic formulae. In one case, measurements were available at both sandface and surface and partial wellhead information was available in the other. We explored a parametric study to assess whether a given wellbore/reservoir system will lend itself to wellhead measurements for valid transient analysis. Reservoir flow capacity (kh) turned out to be the most influential variable.
Practical Application of Pressure-Rate Deconvolution to Analysis of Real Well Tests
Authors: Levitan Michael M. 
Published: December 2007

Abstract
Pressure-rate deconvolution is a long-standing problem of well test analysis that has been a subject of research by a number of authors. A variety of different deconvolution algorithms have been proposed in the literature. However, none of them is robust enough to be implemented in the commercial well test analysis software. Recently, Schroeter, Hollaender, and Gringarten7, 8 published the deconvolution algorithm that has been shown to work even when reasonable level of noise is present in test pressure and rate data. In our independent evaluation of the algorithm we have found that it works well on consistent sets of pressure and rate data. It fails, however, when used with inconsistent data. Some degree of inconsistency is normally present in real test data.
In this paper, we describe the enhancements of the deconvolution algorithm that allow it to be used reliably with real test data. We demonstrate application of the pressure-rate deconvolution analysis to several real test examples.