bluuebunny/crossref_metadata_2025_split huggingface dataset:
3D Porosity Modeling of a Carbonate Reservoir Using Continuous Multiple-Point Statistics Simulation
Authors: Zhang T. , Bombarde S. , Strebelle S. , Oatney E. 
Published: December 2007

Abstract
Training images are numerical representations of geological conceptual models that provide prior information on reservoir architecture. A new emerging geostatistical approach named multiple-point statistics (MPS) simulation allows extracting multiple-point structures from such training images and anchoring these structures to the data actually observed in the reservoir. By reproducing multiple-point statistics inferred from training images, MPS enables the modeling of complex curvilinear structures, for example sinuous channels, in a much more geologically-realistic way than traditional two-point statistics or variogram-based techniques. However, in the original MPS implementation, all multiple-point statistics moments computed from the training image are exported to the reservoir model without processing, which allows simulating only categorical or discretized variables. This implementation is appropriate with clastic reservoirs for which, typically, depositional facies are simulated first using MPS, then porosity and permeability are distributed within each simulated facies using traditional variogram-based techniques. But for reservoirs, in particular in carbonate environments, where porosity and permeability trends/cycles are not closely tied to any facies distribution, simulating porosity/permeability directly using corresponding continuous training images appears to be a more suitable approach.
In this paper, a new filter-based implementation of MPS is proposed to reproduce features from continuous variable training images. First, a set of general filters is applied to the training image to transform (summarize) each training pattern into a set of scores accounting for different aspects of the pattern, such as north-south and east-west gradients and curvatures. The training patterns are classified in the score space, and grouped into a small number of similarity classes. The simulation consists then of visiting each grid node along a random path, identifying the similarity class that best fits to the local conditioning data, and patching a pattern drawn from the selected similarity class. In our study, this new approach was applied to model the 3D porosity distribution of a carbonate reservoir in Kazakhstan. First, the original "categorical" MPS program was used to model the two main reservoir regions, platform and slope, where the spatial porosity distribution is characterized by significantly different features. Interpreted well markers and seismic data were used to condition the modeling of these two regions. Then porosity was distributed in each region using the "continuous" filter-based MPS program described above. The 3D training images used in that second step displayed porosity trends/cycles controlled by the type of geological sedimentation process believed to have occurred in the reservoir.
Want To Make Tree Operations Safer? Why Not Use the DHSV as a Barrier?
Authors: Munday K. , Trim S. , Turna E. P. 
Published: December 2007

Abstract
Industry practice for the design and operation of oil and gas producing wells incorporates a two-barrier policy, and defines an integrity envelope for environmental protection and safe operations. The standard practice when removing or undertaking major operations on the Xmas tree is to set one or more plugs in the production tubing to maintain two barriers between the reservoir and the environment.
This paper assesses the relative risk of using a Down Hole Safety Valve (DHSV) as a qualified barrier during such operations. Quantitative Risk Assessment (QRA) has been used in this study to understand the implications of the change in working practices.
QRA has been used to assess the risks of an uncontrolled flow of fluid from the reservoir when using a qualified DHSV as a barrier as compared to the standard practice of setting one or more wireline plugs. Three representative cases have been considered in this study:

Case 1
examines changing valves downstream of the master valve on a sub sea well.
Cases 2 and 3 focus on platform wells.

Case 2
changing valves downstream of the lower master valve, and

Case 3
removing the Xmas tree.
The study shows that the major risk when using a wireline set plug as a downhole barrier arises from the blowout risk associated with wireline operations. Use of a DHSV as a qualified barrier eliminates the wireline blowout risk, and reduces the overall risk during Xmas tree operations. Hence, the study recommends the use of a qualified DHSV as a barrier, subject to a risk assessment on a case by case basis.
Selection and Evaluation Criteria for High-Performance Drilling Fluids
Authors: Morton K. , Bomar B. , Schiller M. , Gallet J. , Azar S. , Dye W. , Daugereau K. , Hansen N. , Otto M. , Leaper R. , Shoults L. 
Published: December 2007

Abstract
The degree of difficulty and costs of oil and gas wells have continually increased over the past decade. Development operations continue as the economics of exploring and producing for oil and gas have improved with advancements in drilling technology. Advanced drilling technologies such as rotary stearable assemblies, logging-while-drilling (LWD) tools, annular pressure subs and new bit designs have improved the economics of performance-driven wells. With consideration of reducing drilling problems such as torque and drag, stuck pipe, low rates-of-penetration, depleted sands and well bore stability; these wells are generally drilled with non-aqueous fluids (NAF). However, the inherent advantages provided by NAF are increasingly being offset by environmental risks and liabilities.
The paper discusses key criteria to be considered when selecting high performance fluids (HPF) for performance-driven wells. Performance-driven wells are classified as wells that are technically challenging and inherently risky and costly. These types of wells demand the use of HPF to contain costs and deliver well objectives. Additionally, a new high-performance water-based mud (HPWBM) has been developed and field tested as a technically competent and environmentally compliant alternative to NAF on performance-driven wells. Through a process of product substitution, ChevronTexaco has achieved project objectives while improving the environmental impact of using HPF.
Analysis of the Ensemble Kalman Filter for Estimation of Permeability and Porosity in Reservoir Models
Authors: Lorentzen R. J. , Nævdal G. , Vallès B. , Berg A. M. , Grimstad A.-A. 
Published: December 2007

Abstract
It has lately been reported several successful applications where the ensemble Kalman filter has been used to estimate reservoir properties such as permeability and porosity. However, a thorough investigation of robustness and performance is still missing for this approach. In this paper we aim at filling this gap by studying the robustness of the methodology. One aspect which is investigated is how the filter depends on the initial ensemble. As the initial ensemble is created in a stochastic way, one can not be certain that the results obtained from one run represent the filter performance. Another aspect of interest is how prior information can be used to obtain best possible initial fields. The influence of geostatistical information on the estimated solutions is studied. In addition, the quality of the estimated fields is investigated by evaluating if the estimated static fields are reasonable when treated as the solution of the history matching problem.
The estimation technique has been applied to the widely used PUNQ-S3 reservoir model, which is a small size synthetic 3-D reservoir engineering model. Both permeability and porosity are tuned, and measurements consist of well bottom-hole pressures, water cuts and gas-oil ratios. The initial fields are conditioned on the porosities in the gridblocks where the wells are located. By using a synthetic reservoir model it is possible to calculate the uncertainty of forecasts, and compare this with the true solution.
Streamline Tracing on General Triangular or Quadrilateral Grids
Authors: Matringe S. F. , Juanes R. , Tchelepi H. A. 
Published: December 2007

Abstract
Streamline methods have received renewed interest over the past decade as an attractive alternative to traditional finite difference simulation. They have been applied successfully to a wide range of problems including production optimization, history matching and upscaling. Streamline methods are also being extended to provide an efficient and accurate tool for compositional reservoir simulation. One of the key components in a streamline method is the streamline tracing algorithm. Traditionally, streamlines were traced on regular Cartesian grids using Pollock's method. Several extensions to distorted or unstructured rectangular, triangular and polygonal grids have been proposed. All of these formulations are, however, low-order schemes.
Here we propose a unified formulation for high-order streamline tracing on unstructured quadrilateral and triangular grids, based on the use of the stream function. Starting from the theory of mixed finite element methods, we identify several classes of velocity spaces that induce a stream function and are therefore suitable for streamline tracing. In doing so, we provide a theoretical justification for the low-order methods currently in use, and we show how to extend them to achieve high-order accuracy. Consequently, our streamline tracing algorithm is semi-analytical: within each gridblock the streamline is traced exactly. We give a detailed description of the implementation of the algorithm and we provide a comparison of low- and high-order tracing methods by means of representative numerical simulations on two-dimensional heterogeneous media.
Applications of the Coefficient of Isothermal Compressibility to Various Reservoir Situations With New Correlations for Each Situation
Authors: Spivey J. P. , Valko P. P. , McCain W. D. 
Published: December 2007

Abstract
The coefficient of isothermal compressibility (oil compressibility) is defined as the fractional change of oil volume per unit change in pressure. Though the oil compressibility so defined frequently appears in the partial differential equations describing fluid flow in porous media, it is rarely used in this form in practical engineering calculations. Instead, oil compressibility is usually assumed to be constant, allowing the defining equation to be integrated over some pressure range of interest. Thus, the oil compressibility in the resulting equations should be regarded as a weighted average value over the pressure range of integration.
The three distinct applications for oil compressibility in reservoir engineering are 1) instantaneous or tangent values from the defining equation, 2) extension of fluid properties from values at the bubblepoint pressure to higher pressures of interest, and 3) material balance calculations that require values starting at initial reservoir pressure. Each of these three applications requires a different approach to calculating oil compressibility from laboratory data and in developing correlations.
The differences among the values required in these three applications can as high as twenty-five percent. Most published correlations do not indicate the particular application to which the proposed correlation applies.
A correlation equation for oil compressibility has been developed using over 3,500 lines of data from 369 laboratory studies. This correlation equation gives the average compressibility between the bubble point pressure and some higher pressure of interest. Equations to calculate appropriate values of compressibility for the other two applications are presented.
Removal of Debris from Deepwater Wellbores Using Vectored Annulus Cleaning System Reduces Problems and Saves Rig Time
Authors: Connell P. , Haughton D. B. 
Published: December 2007

Abstract
Debris management is a major concern for producers. Wellbore debris is responsible for many of the problems and much of the extra cost associated with extreme water depths and highly deviated holes. This paper discusses procedures and tool systems developed to optimize the efficiencies and economics of debris removal. Issues pertinent to deepwater wellbore cleaning will be discussed, along with the problems associated with removal of debris caused by perforating, milling, etc. The authors will outline techniques for removal of this debris and discuss a tool system that is a workable solution for these problems.
This paper will focus on the use of a Vectored Annulus Cleaning System to remove debris from areas of the wellbore that have normally proven very difficult. The system has been shown to be effective in removing debris from problem areas such as above liner tops or where casing size changes, areas with a loss of annular velocity, and inwells with little to no circulation. Case histories from the Gulf of Mexico and the North Sea will demonstrate how this technology has reduced problems of debris removal while saving rig time by eliminating trips.
Relative Permeability Hysteresis: Trapping Models and Application to Geological CO2 Sequestration
Authors: Spiteri E. J. , Juanes R. , Blunt M. J. , Orr F. M. 
Published: December 2007

Abstract
The complex physics of multiphase flow in porous media are usually modeled at the field scale using Darcy-type formulations. The key descriptors of such models are the relative permeabilities to each of the flowing phases. It is well known that, whenever the fluid saturations undergo a cyclic process, relative permeabilities display hysteresis effects.
In this paper we investigate hysteresis in the relative permeability of the hydrocarbon phase in a two-phase system. We propose a new model of trapping and waterflood relative permeability, which is applicable for the entire range of rock wettability conditions. The proposed formulation overcomes some of the limitations of existing trapping and relative permeability models. The new model is validated by means of pore-network simulation of primary drainage and waterflooding. We study the dependence of trapped (residual) hydrocarbon saturation and waterflood relative permeability on several fluid/rock properties, most notably the wettability and the initial water saturation.
The relevance of relative permeability hysteresis is then evaluated for modeling geological CO2 sequestration processes. Here we concentrate on CO2 injection in saline aquifers. In this setting, the CO2 is the nonwetting phase, and trapping of the CO2 is an essential mechanism after the injection phase, during the lateral and upward migration of the CO2 plume. We demonstrate the importance of accounting for CO2 trapping in the relative permeability model for predicting the distribution and mobility of CO2 in the formation. We conclude that a proper treatment of the nonwetting phase trapping leads to a higher estimate of the amount of CO2 that it is safe to inject.
The Use of Dimensionless Scaling Methods to Predict Field-Scale Tertiary EOR Project Performance
Authors: Simmons J. F. , Falls A. H. 
Published: December 2007

Abstract
The scaling approach presented in this paper has proven effective in modeling the performance of West Texas CO2 projects. This methodology was developed, and has been utilized successfully, to model the performance of the Wasson Denver Unit, which is the world's largest miscible CO2 project. Methods are described for predicting injection and production rates for tertiary enhanced oil recovery (EOR) projects using dimensionless recovery curves. The primary use of the program has been for miscible CO2 flooding; however, the same methods could also be used for other tertiary processes such as alkaline surfactant flooding.
This program, which has been titled "DUSCALE," is based upon dimensionless recovery curves that can be either simulation-based or derived from analog actual project performance. One key attribute of the program is the ability to model the changes in reservoir processing rate that are common in these projects. Such variation impacts both the performance of the underlying waterflood and also the performance of the tertiary EOR project. Underlying waterflood production is forecasted using a throughput-based regression fit of historical pattern-level performance. Predictions are generated for all injected and produced fluids (oil, hydrocarbon gas, NGL yield, water, and CO2).
The program has also proven valuable as a surveillance tool for comparing actual versus predicted performance of an EOR project at the pattern level. Such analysis has identified project areas with good performance that are worthy of larger injected CO2 slugs, and also patterns within projects that are not meeting tertiary recovery targets. The ability to adjust expectations for processing rate variations is critical in such evaluations, as accelerated waterflood production (due to improved reservoir throughput during a CO2 project) can be incorrectly attributed to the CO2 displacement process.
This paper presents the methodology employed in the program and demonstrates, with examples from the Permian Basin, how the program can be used to generate forecasts for field-scale EOR projects. Examples highlighting surveillance applications are also be included.
Field Results: Effect of Proppant Strength and Sieve Distribution Upon Well Productivity
Authors: Huckabee P. , Vincent M. C. , Foreman J. , Spivey J. P. 
Published: December 2007

Abstract
Development of the Pinedale Anticline (PDA) of western Wyoming is proceeding at a rapid pace. During the past five years, approximately 500 million pounds of proppant have been placed into nearly 200 new wells. Despite this high activity level, no clear consensus has emerged from the various operators as to the optimal stimulation design. Proppant costs range from less than 20% to greater than 65% of the stimulation service company ticket dependent on proppant type selected. For one operator, proppant costs represent approximately 30% of the total completion cost and are a target for cost reduction efforts. These cost reduction efforts must be balanced with the economic value of proppant conductivity and its relationship with effective fracture halflength.
This paper summarizes results from a field trial that was implemented to investigate the effect of proppant selection upon productivity from low-permeability (0.0006 – 0.015 md) formations of the Pinedale Anticline. This study compares the production from 452 fracture treatments in 30 new wells completed by Shell Rocky Mountain Production during the past three years. Production logs are used to compare the productivity of fractures propped with 20/40 sand, 20/40 resincoated sand, 20/40 economy light-weight ceramic, broadsieved intermediate strength, and 20/40 intermediate strength proppants. The results from this study are believed to be the first published field comparison of broadly-sieved and tightlysieved ceramics.
This trial predominantly maintained a consistent stimulation strategy to reduce complexity and uncertainty in the analysis of the proppant selection evaluation. Proppant selection was varied by stage dependent on depth and geologic intervals to provide reliable offset comparisons. Results are categorized by geologic interval to reduce uncertainties from variations in reservoir quality and pressure differentials to more accurately assess the impact of altering proppant type. Economic analyses are presented to illustrate the most cost effective products to incorporate into each fracture treatment. Actual field results are compared to model predictions and laboratory results to determine whether proppant strength and sieve distribution affect production in a predictable manner.
Active Slug Management
Authors: Slupphaug O. , Hole H. , Bjune B. 
Published: December 2007

Abstract
Slug flow, or instabilities, in multiphase wells and -pipelines feeding oil- and gas processing facilities may cause operational challenges related to avoiding unplanned partial- or complete shutdowns, satisfying flaring volumes, managing sand production, maintaining on-spec production, proving of fiscal meters, etc. Conventional approaches to manage slug flow in wells and pipelines include: choking the well/pipeline, increasing gas lift rate(s), and/or providing overcapacity to accommodate the slugs that are produced erratically. All these conventional approaches imply inefficient production or expensive over-design. In this paper, a different—from choking and use of gas lift for stabilization—non-intrusive approach to slug management in wells and pipelines is presented. However, it will typically be complementary to other means, like choking and excessive use of gas lift, of handling slug flow challenges. The approach also applies to handling challenges related to oscillations and transients in the total production system, not only in the wells and pipelines. It may be interpreted as slug management from a practical dynamical systems point-of-view. It has emerged as a result of providing oil- and gas field operators with services and solutions with respect to slug management since the late 1990's. The associated base of experience includes hands-on experience from approximately 20 fields—mainly in the North Sea. The approach consists of solutions for automatic control, or, active feedback control, of well(s)/pipeline(s) and associated separators as well as services for generic handling of oscillations/instabilities including control strategy selection and -tuning. Field results from application of the approach are included. The experience gathered during these years supports that an integrated view of the dynamics of well(s)/pipeline(s) and the processing facilities is required in order to sort out proper activities and means for improving the slug management. Furthermore, it is important that this view is based on an analysis of relevant historical data. The analysis phase should involve key personnel from operations like senior operators, production-, and process engineers. It is our experience that operators who, as part of their slug management strategy, include an approach with characteristics similar to the ones summarized above, will improve operations significantly in an efficient and sustainable manner.
An Electrical Analog Facility for Hydrocarbon Reservoirs
Authors: Worthington P. F. 
Published: December 2007

Abstract
A user-friendly type chart has been constructed as an aid to the petrophysical evaluation of water saturation. It provides a basis for the inter-reservoir comparison of electrical character in terms of adherence to, or departures from, Archie conditions in the presence of significant shaliness or low formation-water salinity. The chart describes a continuum of electrical behavior for both water and hydrocarbon zones. In this respect, it is a generalization of earlier approaches that were necessarily restricted to the water zone. This extension is achieved by adopting a generalized geometric factor, the ratio of formation resistivity to water resistivity, regardless of the degree of hydrocarbon saturation. The type chart relates normalized geometric factor to formation-water conductivity, "shale" conductivity and (irreducible) water saturation. The approach has been benchmarked using data from comprehensively studied reservoirs. The application of the method is described with particular reference to rock types, scale effects, core sampling levels and net reservoir criteria. The use of the type charts is illustrated for reservoir units that show different levels of non-Archie effects. The deliverables include reservoir classification, for interpretation strategy and optimum core-data acquisition, and reservoir characterization in terms of analog porosity and saturation exponents. The principal benefit is a reduction in the uncertainty associated with the well-log analysis of water saturation at an early stage in the appraisal/development process when adequate characterizing data are not available.