bluuebunny/crossref_metadata_2025 huggingface dataset:
Petrophysical Properties Under True-Triaxial Stress For Hydrocarbon Recovery Prediction
Authors: Al-Harthy S.S. , Dennis J. , Jing X.D. , Marsden J.R.
Published: December 2007

The production of fluids from a reservoir often reduces pore pressure such that there is an increase in its effective stresses. During water flooding orgas injection the equilibrium rock stresses can also be altered in a similar dynamic manner. An understanding of these changes are of fundamental importance to performance prediction and management of the stress sensitive reservoirs.

Conventional laboratory methods for studying permeability under simulated burial conditions involve hydrostatic stresses, or sometimes anisotropic triaxial loading in which two of the principal stresses are equal. However, such conditions are rarely encountered in hydrocarbon reservoirs, and true-triaxial stresses are more representative. Whilst previous investigators have utilized true triaxial stresses on cylindrical and prismatic samples, such studies have been restricted by the limited deviatoric stress magnitudes which could be achieved with the test systems. In this investigation, laboratory equipment is being utilized to measure rock properties whilst applying the three principal boundary stresses independently using cubic samples. The apparatus uses closed-loop control, and can achieve deviatoric stresses in excess of 200 MPa and pore pressures to 70 Mpa.

This paper reports the experimental system and work which was carried out to examine the permeability hysteresis effect under hydrostatic, triaxial, and true triaxial stress conditions. The experimental data are being incorporated into a reservoir simulator to investigate the changes in hydrocarbon recovery under different stress conditions. The main objectives are to integrate important petrophysical properties such as permeability and porosity with rock mechanics, to investigate how permeability alteration under in situ stress conditions might affect hydrocarbon recovery.

P. 191
Errors in Input Data and the Effect on Well-Test Interpretation Results
Authors: Spivey J. P. , Pursell D. A.
Published: December 2007

Parameter estimation is one of the two principal functions of well test interpretation. Accurate parameter estimation depends on several factors, including correct reservoir model selection, sufficient test data within the flow regime(s) of interest, and accurate input data. The focus of this paper is the effects of errors in input data such as net pay, porosity, viscosity, formation volume factor, flow rate, and compressibility on the results of well test interpretation.

We consider two of the most commonly used reservoir models – a vertical well with wellbore storage and skin, and a finite-conductivity hydraulically fractured well. For the vertical well case, we allow for the presence of one or more boundaries, and for homogeneous or dual porosity behavior.

Many, if not all, of the observations offered in this paper are part of the working knowledge of the full-time well test analyst. However, these observations have not been systematically catalogued and discussed in the literature. The purpose of this paper is to provide just such a systematic catalog and discussion.
Using Reservoir Characterization Results at the Nash Draw Pool to Improve Completion
Authors: Stubbs Bruce A. , Murphy Mark B. , Hardage Bob A. , Martin F. David
Published: December 2007

The Nash Draw Pool (NDP) in southeast New Mexico is a cost-shared field demonstration project in the U.S. Department of Energy's Class III Program. A major goal of the Class III Program is to stimulate the use of advanced technologies to increase ultimate recovery from slope-basin clastic reservoirs. Advanced characterization techniques are being used at the NDP to develop reservoir management strategies for optimizing oil recovery from this reservoir.

Production at the Nash Draw Pool (NDP) is from the Brushy Canyon formation, a low-permeability turbidite reservoir in the Delaware Mountain Group. A major challenge in this marginal quality reservoir is to distinguish oil-productive pay intervals from water-saturated non-pay intervals. An advanced log analysis and interpretation program was developed that can be used to identify net pay in a complex reservoir. By properly identifying productive pay intervals, oil recovery from the Brushy Canyon reservoir is calculated to be 16.7%, rather than the 10% as initially estimated.

Interpretation and integration of recently acquired geological, geophysical, and engineering data revealed that the Brushy Canyon reservoir is much more complex than initially indicated by conventional geological analysis. A new reservoir description is being used to identify "sweet spots" for an aggressive development drilling program, and results of 3-D seismic data and other interpretations are being used for targeted drilling in high-grade areas of the Pool. Reservoir characterization has identified 17 additional vertical locations at the NDP. Due to cultural and potash mine constrictions, some of these wells will be accessible only with deviated/horizontal wells.

This paper presents recent results of an integrated reservoir characterization effort that is being used at the NDP to optimize reservoir management strategies. Because the reservoir is understood in detail, completion procedures and fracture stimulation treatments can be designed more efficiently. Marginal or non-economic zones are not completed which saves perforating, acidizing and fracturing a zone that will not produce enough reserves to return the cost of completion which results in more emphasis being applied to the zones that represent the most potential.

P. 219
More Effective Hydraulic Fracturing in Secondary, In-Fill Developments, Permian
Authors: Johnson Raymond L. , Rodgerson James L.
Published: December 2007

Hydraulic fracturing in the secondary recovery units in the Permian Basin of west Texas is often complicated by a number of factors. Generally, there exists a lack of historical data or information required to effectively design the desired treatment. Therefore, treatments in these fields have often been "cook-booked" and given less engineering attention due to their smaller size and scope. Many times the process is further complicated by the iterative nature required in effective treatment modeling (i.e., historical review, candidate selection, pre-job design, pre-job diagnostics, on-site or post-job modeling, and post-job diagnostics). In this paper, we will outline the steps required to improve these processes without expending excessive resources. Then, we will discuss steps where streamlining the process is warranted without compromising the end result, Finally, we will document and present several cases illustrating effective use of these technologies to obtain more accurate stress profiles and improved fracture treatments in secondary, in-fill development projects.

P. 281
Progressing Cavity Pump (PCP): New Performance Equations for Optimal Design
Authors: Samuel G. Robello , Saveth Ken
Published: December 2007

The drive for energy independence has created a window of opportunity to innovations in oil recovery. New artificial lift methods like progressing cavity pumping (PCP) have been successfully applied to downhole pumping applications. The unique progressing cavity feature has still to be explored fully to handle oil and gas efficiently without any practical problems. The multilobe pumps are also making inroads into the industry to be used under different operating conditions.

Although the design has been mainly based on empirical standards and trial and error modifications, a more phenomenally optimum design of the pump is required to achieve a high efficiency standard. This requires a more basic analytical consideration. Optimal relationship between the pitch and the diameter of the housing is obtained to achieve a maximum flowrate for multi lobe pumps. This makes it possible to design a power section of the pump with some degree of confidence and predict its performance characteristics with reasonable assurance. The practical usefulness of the theory, backed by the fundamental and optimal analysis for incompressible fluid, is demonstrated with numerical examples.

P. 313
Effect of Foam on CO2 Breakthrough: Is This Favorable to Oil Recovery?
Authors: Yaghoobi H. , Tsau J.S. , Grigg R.B.
Published: December 2007

Some surfactants that we tested were found to be more capable of selectively reducing gas mobility by a greater fraction in high- permeability sands. It is expected that foam can mitigate the problem of an early gas breakthrough in EOR processes. Laboratory experiments were conducted to examine the effect of foam on two different systems of porous media with various fluid saturations. The first system was a fired Berea sandstone core with relatively homogeneous permeability. To simulate reservoir heterogeneity, the second system was a composite core of coaxial permeability (high and low) layers in capillary contact. Experiments were conducted in these systems by injecting CO, CO/brine, or CO/foam into core with different fluid saturations (brine, surfactant solution, and oil). The breakthrough time and incremental fluid recovery were recorded and compared. This study indicates that foam could delay CO breakthrough time and improve oil recovery efficiency in both single and composite cores. The experimental results of the composite core tests also shows a significant improvement in oil recovery from the low permeability region, when CO/foam was used.

P. 337
Understanding and Exploiting Four-Phase Flow in Low-Temperature CO2 Floods
Authors: Grigg Reid B. , Siagian Ucok W. R.
Published: December 2007

This paper reviews the effect of multiphase flow on mobility control in CO2 flooding of oil reservoirs. It then presents experimental data on Sulimar Queen reservoir oil and CO2 injection. Swelling tests for CO2 and oil are perform in a visual PVT cell to identify saturation points and non-aqueous two and three phase regions. Slim tube tests used to determine the minimum miscibility pressure (MMP) at three temperatures (78°F, 95°F, and 138°F) are presented. The slim tube tests are also used to show temperature and pressure effects on the development of miscibility.
Prediction of Turbulent Friction in Rod Pumped Wells
Authors: Xu J. , Shirazi S.A. , Doty D.R. , Schmidt Z. , Blais R.N.
Published: December 2007

Frictional forces acting on the rod caused by the rod reciprocating in the flowing fluid significantly affect the prediction and diagnosis of rod-pumping system performance. Available studies of the flow in the tubing combined with moving rods and couplings are limited to laminar flow. The flow is more likely to be turbulent, however, for liquids with low viscosity and for regions near the rod couplings. Therefore in the current study, turbulent flow in the annular region between the stationary tubing wall and the moving rod/coupling is considered.

Computational fluid dynamics (CFD) is employed to simulate turbulent flow in the annular region with moving rods and couplings. Also, a simplified model using a mixing-length method is developed that is much more computationally efficient than the CFD code. The CFD code employing the standard k-model is used to predict turbulent fiction factors in the annulus with the moving rods and couplings. The simplified model is developed to predict turbulent fiction factors in the annulus with the moving rods. The results from these models are compared each other and with the available data published. In addition, the friction factors between the rod/coupling and fluid can be represented in terms of four parameters: the rod to tubing radius ratio, the coupling to tubing radius ratio, the fluid Reynolds number, and the relative rod velocity.

P. 397
Improved Reservoir Description of Shaly Sands Using Conventional Well Log-Derived
Authors: Elgagah Shedid A. , Tiab Djebbar , Osisanya Samuel O.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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
Improved Evaluation and Reservoir Management of Low Permeability, Gulf Coast Reservoirs: Significance of Stress Dependent Permeability
Authors: Davies John P. , Davies David K. , Holditch Stephen A.
Published: December 2007

This paper was prepared for presentation at the 1998 SPE International Petroleum Conference and Exhibition of Mexico held in Villahermosa, Mexico, 3-5 March 1998.
The Chronology of Water-Oil Handling Equipment
Authors: Delgado Alberto , Lee H.M.
Published: December 2007

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

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.

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Review of WAG Field Experience
Authors: Christensen J.R. , Stenby E.H. , Skauge A.
Published: December 2007

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.

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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

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.

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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

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

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.

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