bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Reservoir Description of Shaly Sands Using Conventional Well Log-Derived
Authors: Elgagah Shedid A. , Tiab Djebbar , Osisanya Samuel O. 
Published: December 2007

Abstract
Reservoir evaluation of shaly formations has long been a difficult task. This in turn makes seeking enhanced reservoir description of shaly sand reservoirs much more difficult. This study develops four models and a systematic technique which incorporate conventional log-derived data to identify shale type and hydraulic flow units in shaly sand reservoirs. The four models were derived using available shale models: laminated shale, dispersed shale for low and high shaly formations, total shale, and the Waxman-Smits (W-S) "Cation Exchange Capacity" model. It is found that these four models possess common features in that each flow unit in any shaly sand reservoir can be represented by a straight line on a log- log plot of the "Shaly Reservoir Quality Index" (SRQI) versus porosity. This straight line representing the flow unit yields a unique slope that equal: [1.7 + (m/2)] for laminated shale, [1.7] for dispersed shale, [1.7 + (m/2)] for total shale model, and (1.7+m) for Waxman-Smits model. In addition, each flow unit has a characteristic intercept at (= 1.0 which is equal to the "Shaly Flow Unit Factor" (SFUF).
This study also includes how to apply these models in order to define the shale type and identify different flow units constituting the shaly sand reservoir.
These shaly sand models were validated using a simulated well-log data. The new models, in combination with the technique proposed in this study, represent an effective tool for an enhanced reservoir description of shaly sand reservoirs. In addition, it provides an economical technique due to its inherent use of conventional well log-derived data
P. 427
VERTEX: A New Modeling Method used to Direct Field Development
Authors: Oguztoreli Mustafa , Wong D.W. 
Published: December 2007

Abstract
While cost-reduction has always been an important aspect of any petroleum venture, smaller reserves and lower flow rates have made such considerations vital. A new model called VERTEX is presently being developed to suit this need. VERTEX uses the (boundary) integral equation method to easily but accurately model major natural and man-made well and reservoir characteristics. In particular, hydraulic fractures, horizontal wells, gravel packs, major lateral heterogeneity and irregular reservoir shapes. In this paper, we set out the principles for the mathematical treatment of the subject. WE solution presented in the SPE literature for hydraulically fractured wills. The paper discusses future application for multi-well field development considering hydraulic fracturing horizontal well or infill and extension drilling.
P. 467
Use of Single-Well Test Data for Estimating Permeability Anisotropy of the Naturally
Authors: Guo B. , Schechter D.S. , Banik A. 
Published: December 2007

Abstract
In order to fully understand the performance of waterflooding in Spraberry Trend Area reservoirs, large scale reservoir simulation using a dual-porosity simulator is necessary. The most important input data required by the simulator is the directional fracture permeability and the anisotropy of the reservoir permeability.
This paper reports a new method for estimating directional fracture permeabilities from pressure data recorded during single-well tests. In this study, a new, dual-porosity, dual-permeability, mathematical model has been developed for single phase flow in reservoirs that are naturally, vertically fractured. Fracture spacing is explicitly considered in the model. The model consistently fits a set of single-well-test data obtained from a Spraberry well before and after hydraulic fracturing. The on-trend and off-trend fracture permeabilities before hydraulic treatment have been estimated to be kx = 30 md and ky = 0.09 md, respectively. The anisotropy of the fracture permeability is kx / ky = 322. The on-trend and off-trend fracture permeabilities after treatment have been estimated to be kx = 39 md and ky = 0.9 md, respectively. The anisotropy of the fracture permeability is kx / ky = 43. These results indicate that the hydraulic fracturing treatment significantly improved (10 fold) fracture permeability in the off-trend direction.
This paper provides reservoir engineers with a useful tool for estimating fracture permeability anisotropy and other properties of naturally fractured reservoirs from single-well tests.
P. 477
Mechanics of an Electric Submersible Pump Failure Mode
Authors: Powers Maston L. 
Published: December 2007

Abstract
The occurrence of electric submersible pump (ESP) failures due to spinning diffusers is of a tolerable frequency in moderate operating cost circumstances. However, extremely high well servicing expenses are associated with many ESP applications. Examples include deep wells, arctic locations, offshore wells that must be killed with high-density fluids and sea floor completions. In these or other high cost circumstances, early pump failures of any mode cannot be tolerated.
Longitudinal compressive force is imposed on the diffuser stack of ESP's during assembly to prevent diffuser rotation. If this is done improperly the diffusers can spin due to torque transferred from the impellers, resulting in early pump failure. This paper analyzes the mechanics of the spinning diffuser failure mode and demonstrates why some pumps having inadequate compressive force can pass common pump tests, but subsequently fail in this mode. Equations are developed to calculate the restraining force as it changes under varying conditions and the minimum value required to prevent diffuser spinning. Testing procedures are proposed that would emulate the effects of well conditions conducive to diffuser spinning, thereby detecting the defective pumps currently being missed. Practical examples are included which illustrate the utility of the concepts herein presented.
P. 519
Granite Wash Completion Optimization with the Aid of Artificial Neural Networks
Authors: Shelley Robert F. , Massengill D. Richard , Scheuerman Perry , McRill Paul E. , Hamilton Ray 
Published: December 2007

Abstract
The quality and quantity of information available in the public domain is growing rapidly, and companies are generating inhouse databases to track this explosion of information to improve operating and service performances. 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 a required result.
The subject of this paper is an analysis of granite wash completions in the Red Deer Creek field, Roberts County, TX. The analysis uses an artificial neural network (ANN). Specific areas of interest include any controllable/quantifiable aspect of a well's completion and stimulation procedure—including fluid selection, treatment volume, proppant type and volume, pump rates, and perforation distribution—that affects production outcome. Relevant conclusions are drawn that quantify the effects of reservoir, well, and completion factors on production results. This paper will document a test of methodology on the completion of a new well that resulted in a two-fold gas production increase compared to four previous completions that used only conventional completion optimization techniques.
Classification of Reserves: Guidelines and Uncertainty
Authors: McGilvray W.G. , Shuck R.M. 
Published: December 2007

Abstract
The classification of petroleum reserves is an important function of the petroleum engineer and a fundamental procedure in the oil and gas industry. What on the surface would seem to be a simple undertaking can actually be a very complex procedure. This paper discusses technical guidelines used for the classification of reserves under the reserves definitions adopted by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC) as well as those included in the relevant rules of the United States Securities and Exchange Commission (SEC). The varying technical requirements and guidelines for classification of reserves as proved, probable and possible will be reviewed and discussed. Acquisition of geophysical, petrophysical, geologic, and engineering data is important both quantitatively and qualitatively for reserves classification. The data criteria for each level of classification may vary relative to the classification.
The paper will address the complications, challenges, and inherent uncertainty of reserves estimations. All reserves estimates contain varying degrees of uncertainty related to technical, economic. and political issues. This paper will focus on technical risks associated with geophysical, geologic, petrophysical, and engineering assessments and judgments. The paper will also address why uncertainty exists. how uncertainty fits into reserves definitions and the importance of uncertainty in the classification of reserves.
Since the reserves engineer's job is to plan, gather, assimilate, and analyze all available information using his knowledge and judgment to generate a meaningful reserves estimate the paper will discuss a conceptual procedure for estimation of reserves.
P. 39
A New Approach of Fractured Reservoirs
Authors: Sabathier J. C. , Bourbiaux B. J. , Cacas M. C. , Sarda S. 
Published: December 2007

Abstract
The basic tool for fractured reservoir studies is the dual-porosity (-permeability) model. Using the Warren and Root concept of rectangular parallelepiped blocks, this (sugar box) model is generally considered as unrealistic by geologists. On the other hand fluid flows within the matrix blocks are not simulated (one node) and the matrix-fracture exchanges within a cell are generally lumped in one connection including horizontal and vertical flows. This requires to compute and input pseudo kr-Pc curves which depend on the matrix petrophysical properties, block sizes and fluids present both in the matrix and the surrounding fractures.
To improve the accuracy and speed up the fractured reservoir studies, IFP developed a complete methodology of modelling and simulation which includes: –a software giving a realistic and stochastic picture of the fracture network after a geologic characterization of the different fracture sets;–a software taking the above picture as input and computing the equivalent parameters of a dual-porosity model so that the anisotropy of the fracture system and the oil recovery versus time of a matrix block surrounded by another fluid are the same in the simulator as in the geological model;–a dual-porosity, dual-permeability model which uses the above parameters and where the fracture-matrix flows are simulated according to their direction and to give the true kinetics and final recovery without using arbitrary pseudo functions.–laboratory test technology and procedures to measure, in reservoir conditions, the required parameters. These tests also provided examples to benchmark our simulator. They are not described in the present paper1,2.
This paper describes the complete methodology and details the specific fracture-matrix flow formulation, which could be input in other dual-porosity simulators. The presented cases indicate that geologists and engineers can cooperate in a really-integrated fractured reservoir study based on a realistic picture of the fracture network. In addition, the modification of the matrix-fracture flow terms improves the model accuracy and speeds up the study as it does not require to prepare any pseudo curve.
Improved Estimation of Relative Permeability from Displacement Experiments
Authors: Mitlin V.S. , Lawton B.D. , McLennan J.D. , Owen L.B. 
Published: December 2007

Abstract
Simulation of multiphase flow in porous media requires knowledge of relative permeability functions. A commonly used unsteady-state method of estimating relative permeability is based on interpreting flow data collected from laboratory displacement experiments. In this paper, refinements are outlined, for improving the accuracy of estimated relative permeability pararmeters by accounting for thermal effects for produced fluids, utilizing pre breakthrough differential pressure data in cases where capillary forces are neglected, elimination of convergence problems in history-matching algorithms, and improving the reliability of injected phase relative permeability estimates.
For the gravimetric method of collecting displacement data, the existing procedure of calculating production volumes is improved to account for thermal expansion of fluids in collection vessels, both for imbibition and drainage displacement. The parameter estimation technique is used to determine relative permeability. A semi-analytical procedure, based on the JBN method, utilizes pre-breakthrough differential pressure data, in cases when capillary forces are neglected. This is especially important for low permeability samples, where post-breakthrough production data could be limited. Otherwise, capillary and gravitational forces are accounted for using a finite- difference method.
The history matching procedure requires minimizing the objective function, which is a measure of the deviation between simulated and experimental data. The simulated annealing method is used to avoid possible convergence of the minimization routine to a local, rather than the global minimum of the objective function. Interpretation of relative permeability of the injected fluid from displacement experiments is shown to be less precise than for the displaced fluid. The theoretical analysis rationalizes acquisition of more data during early phases of a displacement experiment. Optimization features discussed in this paper are incorporated in a new, relative permeability simulator.
P. 77
Total Gas Compression Platform Automation Based on PLC's
Authors: Rivera Abelardo 
Published: December 2007

Abstract
Po1-A compression platform belongs to a petroleum platform complex located in the Pemex Exploracion y Produccion's marine zone in the Gulf of Mexico. It receives the natural gas, that is first separated from oil in the production platforms, via two pipelines called high pressure suction and low pressure suction. The natural gas once on the compression platform is conditioned, compressed and sent to Atasta, an onshore re-compression station. It Also produces sweet gas to supply fuel gas for all the equipment and machines located on the platform complex.
Po1-A compression platform handles 320 MCF (million cubic feet) of natural gas per day and 30 MCF of fuel gas per day. Its operation in the marine zone began in 1988 and it belongs to a high gas producer oil field.
A Case History of An Integrated Study of a Mature Carbonate Waterflood
Authors: Bastian P.A. , Gulick K.E. , Forrest J.K. , McVay D.A. , Mora C. Noe , Arguello Leopoldo M. 
Published: December 2007

Abstract
This paper presents a case history of an integrated study of a mature carbonate waterflood located in Mexico. The objective of the study was to determine a redevelopment plan that optimized the remaining hydrocarbon recovery from the field. The field has been in operation for over 40 years. Most of the 343 wells in the field were drilled in the late 1950s and early 1960s. The field has been under waterflood operation since 1967.
This study integrated log analysis, geology and petrography, reservoir and production engineering, and numerical simulation. Because of the age of the field, this study presented some unique challenges. For example, the vintage of most of the open-hole log data required special analyses to determine porosity and water saturation.
We developed a custom PC-based relational database early in the project to manage the large volume of production and injection data and basic reservoir engineering data. This database was one of the most important components of the study because it allowed project team members to access the data easily and quickly.
The reservoir characterization resulted in a 21-layer geological model. We constructed a 3-dimensional, 3-phase numerical simulation model and calibrated it with over 40 years of primary and secondary recovery performance history from 273 wells. Because of the large amount of performance data to history match, we developed a special strategy for the history match of this reservoir's performance.
On the basis of the analysis of this reservoir, we determined that the production rate and remaining recovery could be increased significantly provided that an aggressive redevelopment plan is implemented. This redevelopment plan included reconditioning existing wells, converting wells to water injection and adding infill producers and injectors in the field. The results of this study demonstrate that the simulation model developed for this reservoir is an effective tool for the future management of the field.
P. 145
An Integrated Reservoir Study to Improve Field Performance
Authors: Lopez Juan Diego Yanez , Ferreira Horacio , Carnes Albert C. 
Published: December 2007

Abstract
Waterflood recoveries from certain areas in this large, thick carbonate reservoir were below expectations. An integrated (geological, petrophysical, and engineering) study was undertaken to (1) develop a geological-petrophysical model covering the areas of interest, (2) evaluate past reservoir performance, (3) predict future performance for various operating plans, and (4) make appropriate recommendations based upon technical and economic considerations. It was concluded that low oil recovery resulted primarily from low to very low formation permeabilities, injected water channeling because of fracture treatments administered during primary production, net pay intervals still behind pipe (mainly in producers), and limited control of injection/production well profiles. Results of the study indicated that oil recovery could be increased significantly by infill drilling/waterflood expansion. However, the most attractive plan from an economic viewpoint was to open the unperforated net intervals in existing producers and injectors and to monitor/improve flow profiles. Other enhanced recovery methods were not attractive because of either low permeability or low oil gravity.
P. 155
Deepwater Geohazard Evaluations and Integrated Geotechnical Studies
Authors: Doyle E.H. 
Published: December 2007

Abstract
This paper focuses on Shell's practice for deepwater US Gulf of Mexico integrated geoscience studies with explanations and examples on how to apply and use the methodology. The applicability of high-resolution geophysical data in deepwater depends on:the usefulness and applicability of 3-D exploration-level seismic data for geohazard studies through the use of renderings and other 3-D workstation related products,a review of side scan sonar and subbottom profiler methods and their appropriateness.
Discussed also is the usefulness of multifold data and why 3-D high-resolution acquisition may be a necessary requirement for the future. In addition, present deepwater geotechnical investigation practices are discussed.
Examples of integrated geoscience studies are used to illustrate their use in the design of deepwater foundations.
P. 165
The Next Generation J-Lay System
Authors: McDonald D.N. , Sullivan D.J. , Choi H.S. 
Published: December 2007

Abstract
In 1993, the J-Lay method of pipelaying was chosen to install deep water pipelines to the Shell Oil Company's Auger Tension Lcg Platform. A specialized J-Lay pipe laying system was designed and constructed to lay a portion of these pipelines in water depths ranging from 1200 feet to 2860 feet. Since this work was performed many benefits have been realized relative to the J-Lay process which show this process to be proven, reliable, and cost effective.
This paper will update the history of the J-Lay process in the Gulf of Mexico since the lay of the Auger pipelines including technology improvements and benefits realized. Conclusions regarding the future direction of J-Lay equipment and processes with projected design criteria of future systems will be addressed. In addition, this paper will briefly highlight some important factors when designing a deep water pipeline.
P. 173
Downhole Pressure and Temperature Survey Analysis for Wells on Intermittent Gas Lift
Authors: Hernandez Ali , Garcia Gonzalo , Concho Alejandra Maria , Garcia Roberto , Navarro Ulbio 
Published: December 2007

Abstract
The production of oil wells on intermittent gas lift can be increased by properly selecting the optimum cycle time and injecting the correct amount of gas at the required injection pressure in each cycle. Due to the complexity of the process, some times the production engineer is forced to perform downhole pressure surveys to have a better understanding of the well performance and therefore, improve the quality of the trouble shooting outcome. This kind of procedure is specially important for choke control intermittent gas lift where a precise knowledge of the inflow and outflow behavior of the well is needed.
In this paper, a detailed description of the correct procedure for performing and analyzing a downhole pressure survey is given. The survey procedure is a combination of static and dynamic downhole surveys which when properly done and analyzed, will provide the following information:optimum cycle time;productivity index;current fallback;real fluid gradient;static reservoir pressure and other reservoir properties.
The mathematical procedure used to find the liquid slug length as a function of time and the productivity index is derived in the paper and a computer algorithm to perform these tasks is presented. Actual downhole measurements closely match the computer output.
A 30% increase in production was obtained when the procedure presented in this paper was applied to 10 wells in Lake Maracaibo Gas Lift Field. The surveys outcome and the necessary adjustments are also presented in the paper.
P. 205
A New Methodology to Determine the Optimal Pressures of the Stages in the Separation Oil-Gas
Authors: Sanchez-Olea Eva , Martinez-Romero Nestor 
Published: December 2007

Abstract
The objectives of this work are:to present a new methodology for determimng the number of stages and their optimal pressures,to illustrate the utility of this methodology by apply it to typical field conditions, andto present the features of a computer program named "OPTI PRE", developed to design and analyze the best conditions for oil-gas separation.
Factors influencing separation include tubing pressure (flowing) and the relative amounts of crude oil and natural gas in the hydrocarbons mixture. The change in pressure gives rise to changes in actual flowing volume, in allowable velocity, and in gas and liquid densities.
We present a new methodology to select the optimal pressure of the separation stages of the fluids in surface, which is developed based on an economic analysis. The common criteria used in the field are "Maximum Recovery of Fluids" and "Minimum Requirements of Compression". The technique proposed in this work allow to take better decisions of design, and increases the revenue of the process, we therefore termed it "Maximum Revenues"
This paper also includes the presentation of a computer program developed in Windows environment, named OPTI PRE, to simulate and evaluate the separation process with the three mentioned techniques. We have two different ways to predict the behavior of fluids, Peng-Robinson equation of state and Standing correlation.
The program was developed using numerical techniques, based in Spline methods and quadratic interpolation, instead of the common graphical methods used in the field.
Computerized analysis using automated techniques can provide better estimates than those obtained with the standard graphical analysis.
P. 243