bluuebunny/crossref_metadata_2025 huggingface dataset:
Estimating Drainage Shapes from Reservoir Limit Tests
Authors: Earlougher R.C.
Published: December 2007

The shape factor for a system can be derived with data from a long-term pressure drawdown test and then can be used to estimate the shape of the drainage region and the location of the well in the system. The calculation technique requires only slope and intercept data from plots of short-term drawdown tests and long-term reservoir limit tests.

Introduction

A long-time pressure drawdown test can be used to estimate the volume being drained by a well. Such a test is normally referred to as a reservoir limit test. All reservoir limit testing techniques use the fact that pressure behavior eventually reaches pseudosteady pressure behavior eventually reaches pseudosteady state for constant-rate drawdown in a closed drainage system. At pseudosteady state, bottom-hole pressure varies linearly with time. The proportionality constant depends on the reservoir volume.

We show how to use pressure drawdown data to estimate both the size and geometry of reservoirs. This requires both transient and pseudosteady-state drawdown data. We present an example to illustrate the procedure. All material given here can be applied to injection-well and gas-system testing when appropriate changes are made.

Analysis Method

When a well in a stabilized reservoir is produced at constant rate, q STB/D, the bottom-hole pressure declines. At early times the pressure is given by

,...................(1)

where

pwf = flowing well pressure, psit = production time, hours-162.6

(2) qBm = ,

(3) kh70 .6 qB 0 .0002637 ktp 1hr = p i - ln kh + 0 .80907 + 2s ,

and

B = formation volume factor, RB/STBct = total system compressibility, psi -1h = formation thickness, ftk = formation permeability, mdpi = stabilized formation pressure, psiq = constant production rate, STB/Drw = wellbore radius, fts = skin factor= fluid viscosity, cp= formation porosity, fraction

m (a negative number) is the slope of the linear part of a plot of pwf vs log t, in psi/cycle. p1hr is the intercept of the straight-line portion of that plot at t = 1 hr. If the pwf (vs log t plot is not linear at one hour, the straight-line portion must be extrapolated to t = 1. p 1 hr is commonly used in transient test analysis to p 1 hr is commonly used in transient test analysis to calculate s.

As the system begins to be affected by boundaries, Eq. 1 no longer applies. After sufficient time the pressure follows pseudosteady-state behavior. pressure follows pseudosteady-state behavior.

JPT

P. 1266
The Use of Capillary Tube Networks in Reservoir Performance Studies: II. Effect of Heterogeneity and Mobility on Miscible Displacement Efficiency
Authors: Simon Ralph , Kelsey F.J.
Published: December 2007

Part II of this series extends the network technique to all miscible displacement mobility ratios and introduces a heterogeneity factor called H. As a result, the network model can be used to study the general miscible displacement case, i.e., miscible displacements with all mobility ratios in linear or areal flow systems having a range of heterogeneities. Engineering charts are presented which show the relationship between recovery, mobility ratio, heterogeneity and pore volumes injected.

Introduction

Part I of this series dealt with equal viscosity, and equal-density miscible displacements. Part II extends the network technique to miscible displacements with all mobility ratios. Part II also introduces a heterogeneity factor, H, used in designing network models. The equal-density limitation is retained. Plug flow is assumed in the capillary tubes. The Plug flow is assumed in the capillary tubes. The original fluid and injected fluid are considered ideal so there are no heat or volumetric effects from mixing. Viscosity of the mixtures is discussed in the section on Calculations.

Part II is divided into three main sections. The first discusses the calculation methods. The second shows comparisons of data calculated by the network technique and data measured for real porous media. These comparisons demonstrate that porous media. These comparisons demonstrate that network models can indeed be used to predict the performance of displacements in real porous media. performance of displacements in real porous media. The third section illustrates the application of network methods to reservoir engineering problems. The illustration is accomplished with a series of charts that relate oil recovery to heterogeneity, mobility ratio, and pore volumes injected for the special cases of a linear system (length/width = 3/1) and five-spots.
Solutions to the Three-Phase Buckley-Leverett Problem
Authors: Guzman Rafael E. , Fayers F. John
Published: December 2007

This paper presents method of characteristics (MOC) solutions to the three-phase Buckley-Leverett problem with and without gravity, for the three classes of equations described by Guzmán and Fayers (1997).12 Thus, solutions for equations with single and multiple umbilic points, and mixed elliptic and hyperbolic equations are constructed. A close relation between the mathematical properties of the equations (in terms of location and quantity of umbilic points) and the physics of flow is described. This relationship can be observed by the effect of gravity on the efficiency of the displacement, the formation of oil and water banks, and the presence of a unique or infinite solution paths within the three-phase flow region for a class of solutions. Elliptic regions did not generate physically inadmissible effects and stable shocks with saturations on opposite sides of elliptic regions were constructed in all the cases examined.
A Compositional Model for CO2 Floods Including CO2 Solubility in Water
Authors: Chang Yih-Bor , Coats B. K. , Nolen J. S.
Published: December 2007

This paper presents a three-dimensional, three-phase compositional model for simulating CO2 flooding, including CO2 solubility in water. In this model, CO2 is allowed to dissolve in the aqueous phase, while all other components, except water, exist in the oil and gas phases. Oil- and gas-phase densities and fugacities are modeled by a cubic equation of state. The aqueous phase properties are functions of the amount of dissolved CO2.CO2 solubility is computed using a CO2 fugacity coefficient table that is converted internally from input CO2 solubility data as a function of pressure at reservoir temperature. Correlations for computing the solubility of CO2 in water and other properties of CO2-saturated water are presented. The results for simulation runs with and without CO2 solubility in water are shown for comparison.
ALWORKS - An Artificial Lift Surveillance Tool
Authors: Burleson G. L. , Redden J. D.
Published: December 2007

More effective use of computing tools for production surveillance by operations and engineering personnel is critical to increases in profitability. Exxon's Artificial Lift Workstation (ALWORKS) is a software package that allows easy access to electronically stored data and provides that data to various surveillance, analysis, and design applications with minimal user effort. Operations personnel have field-tested the software, and they have noted significant increases in productivity that will lead to increases in profitability.
Pulse Testing: Mathematical Analysis and Experimental Verification
Authors: Odeh A.S. , McMillen J.M.
Published: December 2007

This paper covers theoretical research on pulse propagation in linear cores saturated with air, and propagation in linear cores saturated with air, and discusses bow pulse tests in these systems can be analyzed to provide a measure of the porosity and permeability of the porous medium. It also covers permeability of the porous medium. It also covers experimental work designed to compare these properties, as calculated from pulse-test data, with properties, as calculated from pulse-test data, with those determined by conventional measurements. The paper shows that, when such pulse data are analyzed correctly, the comparison is very favorable; i.e., permeability values vary no more than 3 percent and porosity values no more than 0.5 percent. We conclude that pulse experiments with linear cores saturated with air give data, which when analyzed by methods based on the diffusion equation, give permeability and porosity values comparable with permeability and porosity values comparable with those obtained by conventional methods.

Introduction

Pulse testing is a recently developed method for evaluating reservoir storage capacity and fluid transmissibility. Papers have described the basic theory, based on the diffusion equation, and techniques of pulse testing as applied to field operations. Although some of the papers describe field applications, none report laboratory experimental investigations of pulse testing. This paper covers experimental and theoretical research on pulse propagation through porous media. It tests the adequacy of the use of the diffusion equation as a basis for interpreting pulse-test data.

Using the diffusion equation, the theory of pulse propagation in a linear porous system and a method propagation in a linear porous system and a method of interpreting the experimental data are derived. A few experiments conducted on long Berea cores saturated with air are described. The porosity and permeability values were determined by gas expansion permeability values were determined by gas expansion and steady-state flow, respectively, and the values were compared with those theoretically calculated from experimental pulse data. The comparison shows that the values determined by the conventional methods compare well with those calculated from the pulse data.
Evaluation and Economical Feasibility of Polymer-Assisted Surfactant Flooding for the Gullfaks Field, Norway
Authors: Maldal Trygve , Gilje Eimund , Kristensen Reidar , Kårstad Terje , Nordbotten Atle , Schilling B. E. R. , Vikane Olav
Published: December 2007

This paper presents parts of the work performed to develop and qualify a polymer-assisted surfactant flooding (PASF) system for economical use in the Gullfaks Field, Norway. The paper addresses experimental work done in the laboratory, numerical simulation of PASF, and the evaluation of the potential for PASF in full-field scale.

The experimental part comprises core-flooding experiments at different temperatures, pressures, and gas/oil ratios (GOR) to optimize the PASF system for the Gullfaks Brent formation conditions. The surfactant in the PASF system is a branched sulphonate (5,000 ppm) and xanthan (500 ppm). The surfactant-polymer slug is followed by a slug of xanthan (500 ppm) for mobility control. No cosolvent is used. In coreflood experiments more than 70% of the waterflood residual oil was recovered.

Using reservoir simulation, a suitable pilot area was found in the Brent reservoir. Additional results from simulations were the amount of chemicals, the time needed for the pilot test, and additional oil recovery.

Much effort was put into estimating the full field PASF potential. First, the areas of the field where PASF possibly could be used were selected. Key factors were existing and planned well locations, production data, and long-term production forecasts. Then, the amount of chemicals needed and the expected technical efficiency for each area were calculated. To verify these calculations, an area of the field containing two possible injection wells and three producers was selected for a simulation study. This area was considered the most promising area for PASF.

The main conclusion from this work is that, with the present crude-oil price and chemical costs, the PASF process is not economically attractive for use in the Gullfaks field, mainly because the residual oil was considerably lower than believed at project start.
Annulus Unloading Rates as Influenced by Wellbore Storage and Skin Effect
Authors: Ramey Henry J. , Agarwal Ram G.
Published: December 2007

The modern trend in well testing (buildup or drawdown) bas been toward acquisition and analysis of short-time data. Pressure data early in a test are usually distorted by several factors that mask the conventional straight line. Some of the factors are wellbore storage and various skin effects such as those due to perforations, partial penetration, non-Darcy flow, or well stimulation effects. Recently, Agarwal et al. presented a fundamental study of the importance of wellbore storage with a skin effect to short-time transient flow. This paper further extends the concept of analyzing short-time well test data to include solutions of certain drillstem test problems and of cases wherein the storage constant, CD, undergoes an abrupt change from one constant value to another. An example of the latter case is change in storage type from compression to liquid level variations when tubinghead pressure drops to atmospheric Arks production. The purpose of the present paper is to: production. The purpose of the present paper is to:

- present tabular and graphical results for the sandface flow rate, qsf, and the annulus unloading rate, qa, as a fraction of the constant surface rate, q, and

- illustrate several practical well test situations that require such a solution.

Results include a range of values of the storage constant, CD, and the skin effect, s, useful for well test problems. problems. Annulus unloading or storage bas been shown to be an important physical effect that often controls early well test behavior. As a result of this study, it appears that interpretations of short-time well test data can be made with a greater reliability, and solutions to other storage-dominated problems can be obtained easily. Techniques presented in this paper should enable the users to analyze certain short-time well test data that could otherwise be regarded as useless.

Introduction

In a recent paper, Agarwal et al. presented a study of the importance of wellbore storage with a skin effect to short-time transient flow. They also presented an analytical expression for the fraction presented an analytical expression for the fraction of the constant surface rate, q, produced from the annulus

Although the rigorous solution (inversion integral) and long- and short-time approximate forms were discussed, neither tabular nor graphical results ofdpwD the annulus unloading rate, CD, were given.dtD It now appears that such solutions are useful in certain drillstem test problems and in cases wherein the storage constant, CD, changes during a well test. An example is change in storage type from compression to liquid level change when tubinghead pressure drops to atmospheric during production. pressure drops to atmospheric during production. The purpose of this study is to (1) present tabular and graphical results for the sandface flow rate and the annulus unloading rate and (2) illustrate several practical well test situations that require the practical well test situations that require the solutions.
Three-Phase Well-Level Production Allocation at Prudhoe Bay
Authors: Bergren F. E. , Lagerlef D. L. , Feldman Scott
Published: December 2007

Three-phase production-allocation programs have continuously evolved in the Prudhoe Bay Eastern Operating Area (PBEOA) over the past 19 years. These programs are necessary because the actual production rate of a well can be measured only when a well is being tested. Since each well is tested for about 6 hours per week, some method of estimating well production rates in real time while the well is not being tested is required. These estimates are used to optimize well and field production as surface processing and product shipping constraints vary. These estimates are also used to estimate field production rates in real time, track well performance, and allocate production volumes to wells for accounting and reservoir management purposes.

Rate tables for most naturally flowing wells and all gas lifted wells are based upon the Fetkovich inflow performance model and tubing performance relationships (TPR's) developed from various tubing hydraulics models. Specialty rate table programs allow engineers to allocate production to wells which always produce at the same choke setting, wells which are in the process of gassing out, and to automatically allocate wells which maintain consistent performance. A recent upgrade of the allocation system, utilizing current generation computer hardware, communications hardware, and software has resulted in a 60% reduction in engineering time required for production allocation.

The allocation process discussed here can be applied to many other fields to improve the link between field well test data and the optimization of field production rate, estimation of well and field production rates in real time, well performance tracking and allocation of field production to wells for reservoir management and accounting purposes.
Explosive Termination of a Wild Well Evaluation of a Concept
Authors: McLamore R.T. , Suman G.O.
Published: December 2007

A concept to terminate a wild well by detonating a subsurface explosive charge placed in a relief well near the wild well has been investigated and found to be feasible. The study described in this paper dealt with the application of conventional chemical explosives; however, the concept is equally valid for nuclear explosives.

Introduction

In March, 1970, the Shell Cox No. 1 well near Jackson, Miss., blew out during drilling, caught fire, and eventually cratered and extinguished itself. The well was a 22,000-ft high-pressure sour-gas well. Flow rates while the well was blowing out were estimated to range from 20 to 100 MMcf/D. Data gathered on site indicated that the crater had plugged at a relatively shallow depth, causing an underground blowout.

Plans were developed to drill a relief well to total depth. Drilling time of this well was estimated to be 12 to 18 months. The great depth, the directional drilling problems, the presence of sour gas, and the tightness of the formation were severe conditions that dictated the development of a novel concept to kill the well quickly.

Two such concepts were developed. The first consisted of (1) drilling an intercept well to a depth of approximately 10,000 ft in such a way that the casing in the intercepting well was in contact with the casing in the Cox No. 1 well, (2) cementing the two strings together, (3) perforating the strings to create communication, and (4) pumping cement into the wild well to kill it. This is the technique that was eventually used.

The second concept consisted of (1) drilling a 10,000-ft intercept well converging to within 15 ft of the wild well, (2) washing a large cavity at the bottom of the hole, (3) pumping conventional explosives into the cavity, and (4) detonating on command. The explosion would create a larger cavity, crush and rubble the rock, collapse and shatter the casing in the wild well, and stem the flow of gas at that depth. The purpose of this paper is to discuss the program that was carried out to evaluate this concept.

Calculations, using finite-difference programs, were made to evaluate the effect of explosive properties and rock properties on the cratering and ground motion associated with the detonation so that the shot could be properly designed. In addition, an explosive formulation was developed that met the requirements for safe handling and pumping on the surface and detonation in a high-pressure and high-temperature environment.

From the study it has been concluded that the concept of using explosives to terminate a wild well is feasible. Although the concept is untried to date in this country, the Russians have demonstrated the soundness of it by killing two wild gas wells using nuclear explosives.

Project Planning Project Planning After the explosive kill concept was conceived, the following program was developed to evaluate it and to bring it to completion, if necessary.

Phase 1 Determine the feasibility of explosively terminating Cox No. 1 and develop specific proposals to accomplish the job.

JPT

P. 1084
DPARS Production and Reserves System: Evolution of a Corporate Tool
Authors: Borcholt Matthias , Robertson G. D.
Published: December 2007

We describe the evolution of a customer-driven, fit-for-purpose database tool that intelligently combines reserves, production, entitle-ment/sales, capital expenditures (Capex), operating expenditures (Opex), well scheduling, and separator test data. The tool, Deminex Production and Reserves System (DPARS), evolved from a singleuser application on a portable personal computer (PC) to a networked, multiuser, corporate tool used worldwide in a midsize international oil and gas E&P company.
The Architecture of a Plug-and-Play Kernel for Oilfield Software Applications
Authors: Ward V. L. , Seaton C. P.
Published: December 2007

It is now common practice for engineers to use PC software to design and evaluate oilfield services. Rapidly changing technology in PC software has made it necessary for organizations to release new applications quickly to remain competitive. We designed a plug-and-play kernel for the computer aided design and evaluation (CADE) applications to reduce development time and time to market. Our paper discusses the kernel used in the CADE software in detail.
The Application of World Wide Web Technology in a Learning Organization
Authors: Evans D. C.
Published: December 2007

In mid-1995, the departments responsible for drilling, completion, and workover operations on behalf of three North Sea subsidiaries of a major multinational oil company integrated into a single North Sea drilling group (NSDG). As part of a global drilling organization, the NSDG now serves the three business units in the North Sea area by providing a shared-service capability to its respective exploration and asset-management teams. One of the fundamental problems that the new group faced was how to share knowledge and expertise effectively among team members in several locations. A solution to this problem was essential for the group to achieve its goals of minimizing total life-cycle well costs, increasing efficiency through the integration of existing teams, and continuing to develop as a center of excellence within a global drilling operations network.

The group identified World Wide Web (WWW) technology as a cost-effective solution that could provide a mechanism for the transfer of engineering technology and learnings, both within the group and throughout the worldwide drilling community. The WWW has proved to be a powerful new medium for the communication of dynamic information, such as reports, business objectives, performance measures, policies, and other reference material, as well as being a valuable source for technical information that otherwise might have been overlooked in our decision-making processes.

This approach has enhanced our ability to optimize the use of existing resources, yielding significant economic benefits to each of the participating customers. A specific example is the role of the WWW in the continuing development and implementation of the drilling-management system (DMS), an organizational learning tool now being introduced widely to optimize the planning, implementation, and evaluation of wells.
Integration of Old and New Measurements To Optimize Redevelopment of the Lower Lagunillas Reservoir of Bloque IV, Lake Maracaibo, Venezuela
Authors: Bryant I. D. , Baygün Bülent , Herron M. M. , Matteson Abigail , Ramamoorthy Raghu , Stewart Lisa , Tariq S. M. , Coll Carolina , Cordova Pedro , de Villarroel Helena Gamero , Hernández Luis , Jimenez Zulay , León Karmele , Rondón Luis
Published: December 2007

The Lower Lagunillas of Bloque IV of the Bachaquero field is a supergiant reservoir that has been in production since 1956. We have carried out a pilot reservoir characterization study in the central part of the field, in which we have integrated all the available data into three-dimensional (3D) reservoir simulation models whose purpose is to optimize redevelopment of the area with horizontal wells.

An analysis of the history of production was undertaken to gain an insight into the reservoir dynamics. This analysis indicated the inefficiency of gas injection in providing pressure support to the pilot study area and demonstrated the presence of active aquifer encroachment from the south. Anomalies in production behavior and fluid characteristics indicate both lateral and vertical compartmentalization of the reservoir.

We have integrated Fourier transform infrared (FTIR) measurements of mineralogy from old cores with a comprehensive logging suite in a new well to re-evaluate older, sparse logging suites. The application of a mineral-based log evaluation and high-resolution processing of the new logs has led to a significant increase in estimates of oil initially in place in the study area. We have used a novel approach to estimate permeability in all wells in the study area. Combining these new evaluations with a revised geological model enabled us to recognize 11 geological layers throughout the area. Formation pressure measurements confirm that partial barriers to vertical communication exist between most of these layers. Cased hole saturation measurements and historical production data indicate an uneven sweep of these layers, such that five layers contain bypassed oil that could be recovered by horizontal wells. We have constructed very detailed simulation models that describe the lateral and vertical variation in petrophysical properties of each of these layers. These models have been used to select the optimum locations for horizontal wells and to optimize their drilling sequence and design. It is estimated that each of these wells could recover 1 to 1.5 million stock-tank barrels (STB) within 5 years.

The first well drilled as a result of this study has produced dry oil at rates up to 469 BOPD from a zone not previously considered as a pay zone.
Constrained Derivatives in Natural Gas Pipeline System Optimization
Authors: Flanigan Orin
Published: December 2007

Here is a promising new method for optimizing both the facilities and the operations of integrated natural gas pipeline systems. The balancing-of-nodes calculation method is used as a system model and the method of constrained derivatives is used in conjunction with this model to optimize the system represented.

Introduction

Historically, differential calculus has been a prime tool in optimization work. When certain conditions are present, differential calculus can be a simple and powerful tool. These conditions are: powerful tool. These conditions are:

(1) The system can be described by a set of continuous analytical equations.

(2) The system contains no constraints.

(3) The system equations are differentiable.

When these (and sometimes other) conditions are met, the classical approach is to take the first derivative of the system equations with respect to certain specified variables. These derivatives are set equal to zero and the resulting equations are solved for their various roots. The second derivatives are then used to evaluate whether the roots are maxima, minima, or points of inflection. A physical representation of a simple unconstrained system is a single hill. Differential calculus will lead us to the top of the hill.

Unfortunately, the range of actual problems to which this procedure can be applied is quite limited. Most problems have at least some constraints; and many systems of interest are severely constrained. Some examples of these constraints are: (1) the pressure must not exceed a certain value; (2) the temperature must be between certain limits; (3) limits are imposed on the flow rates.

These constraints to the system may be visualized as a series of fences on the hill that usually prevent an explorer from reaching the top of the hill. The optimum or maximum is the highest point on the hill that can be reached without crossing the fence. In this case, the classical differential calculus approach is useless.
Shale Compaction
Authors: Smith J.E.
Published: December 2007

The compaction of shales or other fine-grained compressible rocks is described by a mathematical model, and specific solutions are presented graphically. The model treats the presented graphically. The model treats the upward and downward movements of the water the solid matrix in very extensive, uniform, flat-lying units. It may readily be adapted treat the compaction of sands. The principal elements of the model are:

(1) continuity equations for the water and solid matrix;

(2) Darcy's law;

(3) an expression for the fluid potential;

(4) an equation for the total vertical stress;

(5) an empirical relationship between porosity and the difference between the total vertical stress and the fluid pressure; and

(6) an empirical relationship between permeability and porosity.

From these elements an expression is derived for the porosity within the unit in terms of the space and time coordinates and boundary conditions, for the approximation that the densities of the water and the solid matrix are constant. Numerical solutions for the fluid pressure, the total vertical stress, the pressure, the total vertical stress, the porosity, the permeability, and the velocities porosity, the permeability, and the velocities of water and solid matrix were obtained as profiles through the unit at close time intervals, profiles through the unit at close time intervals, and representative results are displayed. The events followed are:

(1) shale sedimentation;

(2) a time lapse following shale sedimentation;

(3) sedimentation of a normally pressured unit over the shale unit; and

(4) a final time lapse with no sedimentation.

Two boundary conditions for the base of the shale unit are considered:

(1) the underlying unit is impermeable, and

(2) the underlying unit is a normally pressured sand.

In the latter case, water flows both upward and downward out of the compacting unit. The solutions show that pore water pressures much greater than normal are obtained and may persist for tens or hundreds of millions of years. It is also found that a shale unit rapidly buried beneath a thick normally pressured sand develops a zone near the sand-shale boundary of reduced porosity and permeability in which the pore water pressure permeability in which the pore water pressure gradient is very large.

Introduction

The presence of low density overpressured shales or mudstones in a sedimentary sequence influences the operations of petroleum exploration, drilling and production. During the exploration phase such low density fine-grained rocks influence the interpretation of seismic and gravity surveys. During the drilling of prospects, the mud casing and log programs and prospects, the mud casing and log programs and safety are affected by high pressures. During production, the possible influx of shale water production, the possible influx of shale water requires investigation.
Three-Dimensional Reservoir Description From Multiwell Pressure Data and Prior Information
Authors: He Nanqun , Reynolds Albert C. , Oliver Dean S.
Published: December 2007

Bayesian estimation techniques are applied to generate three-dimensional permeability and porosity fields conditioned to prior means, variograms, hard data and/or multiwell pressure data. A posteriori variances are generated to obtain a measure of the uncertainty in the rock property fields, or equivalently, a measure of the variability in realizations of the rock property fields. These a posteriori variances can also be used to quantify the value of data, i.e., to determine the reduction in uncertainty achieved by adding a particular type of data. A key ingredient of our methodology is the development and implementation of an efficient procedure to estimate sensitivity coefficients for three-dimensional single-phase flow problems.
The Permeability Variogram from Pressure Transients of Multiple Wells: Theory and 1-D Application
Authors: Yortsos Yanis C. , Al-Afaleg Nabeel
Published: December 2007

This paper presents a new approach for the estimation of the large-scale correlation function of reservoir heterogeneity from the analysis of the pressure transient response of multiple wells. The approach is based on the theory of small fluctuations of the logarithm of the permeability and models the response of the "ensemble-average pressure", obtained by averaging the pressure response of multiple well tests. A non-local difFusivity equation for the ensemble-average pressure, which incorporates directly the permeability correlation function, is obtained, from the analysis of which the permeability semi-variogram of the reservoir can be constructed in principle. We consider a particular application to 1-D geometries, where a type-curve is also derived for the case of an exponential correlation function. Numerical simulations results support the applicability of the method.
Integrated Reservoir Characterization Study of a Carbonate Ramp Reservoir: Seminole San Andres Unit, Gaines County, Texas
Authors: Wang F. P. , Lucia F. Jerry , Kerans Charles
Published: December 2007

One of the important issues in constructing geologic and reservoir models is to define geologic frameworks. A geologic framework is fundamental to defining flow units, to interpolating well data, and thereby to modeling fluid flow. For the Seminole San Andres Unit (SSAU), the high-frequency cycles (HFC's) and rock-fabric facies identified on outcrop analogs and cores were used to correlate wireline logs. Reservoir and simulation models of the outcrop and a two-section area of SSAU were constructed with rock-fabric units within the HFC's as a geologic framework. Simulations were performed using these models to investigate critical factors affecting recovery.

HFC's and rock-fabric units are the two critical scales for modeling shallow-water carbonate ramp reservoirs. Descriptions of rock-fabric facies stacked within HFC's provide the most accurate framework for constructing geologic and reservoir models, because discrete petrophysical functions can be fit to rock fabrics and fluid flow can be approximated by the kh ratios among rock-fabric flow units. Permeability is calculated using rock-fabric-specific transforms between interparticle porosity and permeability. Core analysis data showed that separate-vug porosity has a very strong effect on relative permeability and capillary pressure measurements.

The effect of stratigraphic constraints on stochastic simulation was studied. Geologic models generated by a conventional linear interpolation, a stochastic simulation with stratigraphic constraints, and a stochastic simulation without stratigraphic constraints were compared. The stratigraphic features of carbonates can be observed in stochastic realizations only when they are constrained by rock-fabric flow units. Simulation results from these realizations are similar in recovery but different in production and injection rates.

Scale-up of permeability in the vertical direction was investigated in terms of the ratio of vertical permeability to horizontal permeability (kvh). This ratio decreases exponentially with the vertical gridblock size up to the average cycle size of 20 ft (6.1 m) and remains at a value of 0.06 for a gridblock size of more than 20 ft (>6.1 m), which is the average thickness of HFC's. Simulation results showed that the critical factors affecting recovery efficiency are stacking patterns of rock-fabric flow units, kvh ratio, and dense mudstone distribution.
Application of Wavelet Analysis to Upscaling of Rock Properties
Authors: Chu Lifu , Schatzinger R. A. , Tham M. K.
Published: December 2007

Although numerous upscaling techniques are reported in the literature, efficiently computing reasonably accurate equivalent rock properties from geological data at fine scale remains difficult. This is especially true for facies with multiple lithologies under multiphase-flow conditions. Because of the nature of multiscale heterogeneity inherent in petroleum reservoirs, the equivalent rock and flow properties will vary with the scales of heterogeneity. Therefore, upscaled properties under multiphase-flow conditions cannot be estimated without reference to the absolute scales of heterogeneity.

Wavelet analysis is a multiresolution framework; thus, it is well suited for upscaling rock and flow properties in a multiscale heterogeneous reservoir. The compact support property of the wavelet transform assures efficient computation. Choice of regularity provides a flexible way to control the smoothness of the resulting up-scaling properties.

In this study, we developed a new procedure to improve significantly the computational efficiency and accuracy of upscaling for generating equivalent rock and rock-fluid properties under various geological and flow conditions based on multiresolution analysis of wavelet transforms. Additionally, we explored a wavelet reconstruction method to provide a basis for downsampling fine-scale rock property fields from information at various levels of coarser scale. The beauty of the method is that because the equivalent properties at different length scales are computed recursively, the interdependent influences of the heterogeneities on the scales are included effectively. We demonstrate the method by successfully applying it to upscale interbedset and interfacies reservoir properties of Almond formation outcrops under multiphase-flow conditions.
Backflow in Twin-Screw-Type Multiphase Pump
Authors: Egashira Kazuyuki , Shoda Shinji , Tochikawa Tetsuro , Furukawa Akinort
Published: December 2007

The performance of a twin-screw-type multiphase pump was investigated from the viewpoints of backflow in a gap along the twin-screw shafts and of scaleup parameters. Although both the backflow and the scaleup parameters have been recognized as important factors in developing multiphase pumps, they have not yet been clarified.

The twin-screw pump was equipped with pressure sensors, set in the multiphase-test facility, and experimented with under various conditions to clarify the relationship between backflow rates and factors such as differential pressure, gas-void fractions (GVF's), and the rotation speed of the shaft.

A physical model was proposed with the empirical relationship of pressure distribution along the screw, and was successfully associated with scaleup parameters, such as the geometrical data of the twin-screw pump. Then it was used successfully to simulate the backflow in twin-screw pumps on relatively broad experimental conditions, judging from the comparison between the model and the experimental data.
CFD Simulation of Single-Phase and Two-Phase Flow in Gas-Liquid Cylindrical Cyclone Separators
Authors: Erdal Ferhat M. , Shirazi Siamack A. , Shoham Ovadia , Kouba Gene E.
Published: December 2007

The petroleum industry has shown interest in utilizing the Gas-Liquid Cylindrical Cyclone (GLCC) separator as an alternative to the vessel-type separator. Thus, it is important to develop predictive tools for design and to improve the technology of the GLCC. Previous studies have resulted in mechanistic models capable of predicting the operational envelope for liquid carryover. However, these models do not address details of the complex flow field in the GLCC and related phenomena such as gas carry-under. This paper presents computational fluid dynamics (CFD) simulations of single-phase and two-phase flow in several GLCC configurations. The CFD simulations are compared with experimental data including tangential velocity profiles and tangential velocity decay. Good agreement is observed between the data and the simulations. An axisymmetric model for the GLCC is also developed. The axisymmetric simulations, which are computationally efficient, give good results as compared to the three-dimensional simulations. Preliminary two-phase flow simulations are also performed to predict the gas void fraction distribution in the GLCC.
Effects of Heterogeneity and Wetting on Relative Permeability Using Pore Level Modeling
Authors: Blunt Martin J.
Published: December 2007

We present a three-dimensional, capillary equilibrium based, pore level network model that computes relative permeability and capillary pressure for drainage and imbibition cycles. The model accounts for wetting layers in crevices of the pore space, cooperative pore filling and different contact angles. Arbitrary distributions of pore size with different spatial correlations are studied. We show that relative permeabilities for unconsolidated media can be represented in the model using spatially uncorrelated distributions of pore size, but that curves typical of consolidated rock can only be explained by allowing spatial correlation in the pore structure. We also study the effects of flow in wetting layers and different types of cooperative pore filling. This represents changes in contact angle from a completely water-wet system to a neutrally-wet rock. Relative permeability can be extremely sensitive to small changes in contact angle. In general, the residual non-wetting phase saturation decreases as the system becomes less strongly water-wet.
A Decision-Support System for Economic Analysis and Risk Assessment of Subsea Development Scenarios
Authors: Dyer N. J. , Ford J. T. , Tweedie A.
Published: December 2007

The decision to develop a small (< 100 million bbl) oil field in the U.K. sector of the central/northern North Sea requires a careful assessment of all aspects of the field-development plan—the reservoir model (reserves and production profile), capital and operating costs, and the current economic climate (oil price, interest rates, and tax regime). This paper describes the development of a knowledgebased software package that allows a "quick-look" assessment of the overall economics and risk profile associated with the development of small oil fields in this region. It is a modular system that uses a cost database, cost-adjustment algorithms, cash-flow analysis engine, and simulation procedures to integrate and analyze the impact of reservoir and production characteristics, costs [capital expenditures (Capex) and operating expenditures (Opex)], and economic factors on the decision to develop such a field. The production-system configurations considered by the system are (1) an unmanned wellhead platform tied back to a third-party platform for fluid pro- cessing/export; (2) a floating production, storage, and offloading system (FPSO) with oil export through a shuttle tanker and gas export through a tie-in to the existing North Sea gas pipeline infrastructure; and (3) a straight tieback from a group of subsea wells to a third-party platform for fluid processing/export.
Multiphase Flowmeter Successfully Measures Three-Phase Flow at Extremely High Gas-Volume Fractions—Gulf of Suez, Egypt
Authors: Leggett R. B. , Borling D. C. , Powers B. S. , Shehata Khalid , Halvorsen Martin , AboElenain Adel
Published: December 2007

A multiphase flowmeter (MPFM) installed in offshore Egypt has accurately measured three-phase flow in extremely gassy flow conditions. The meter is completely nonintrusive, with no moving parts, requires no flow mixing before measurement, and has no bypass loop to remove gas before multiphase measurement. Flow regimes observed during the field test of this meter ranged from severe slugging to annular flow caused by the dynamics of gas-lift gas in the production stream. Average gas-volume fraction ranged from 93 to 98% during tests conducted on seven wells.

The meter was installed in the Gulf of Suez on a well protector platform in the Gulf of Suez Petroleum Co. (Gupco) October field, and was placed in series with a test separator located on a nearby production platform. Wells were individually tested with flow conditions ranging from 1,300 to 4,700 B/D fluid, 2.4 to 3.9 MMscf/D of gas), and water cuts from 1 to 52%. The meter is capable of measuring water cuts up to 100%.

Production was routed through both the MPFM and the test separator simultaneously as wells flowed with the assistance of gas-lift gas. The MPFM measured gas and liquid rates to within ± 10% of test-separator reference measurement flow rates, and accomplished this at gas-volume fractions from 93 to 96%. At higher gas-volume fractions up to 98%, accuracy deteriorated but the meter continued to provide repeatable results.
Formation Evaluation From Logging on Cuttings
Authors: Santarelli F. J. , Marsala A. F. , Brignoli Marco , Rossi Elio , Bona Nicola
Published: December 2007

This paper presents an overview of a vast research project called Formation Evaluation 2000, which was undertaken by Agip SpA and was aimed at characterizing in real time the formations encountered during drilling by means of measurements on drill chips. To date, the project has demonstrated the feasibility of obtaining representative values of P- and S-wave velocities, rock strength and deformability, permeability, porosity, density, residual fluid con- tent, and saturation. Further work is under way to determine the pore-size distribution, the thermal expansion coefficient, and the electrical resistivity of the rocks from measurements on cuttings.

The paper presents the methodology used to systematically develop these technologies and illustrates the results obtained to date during the various sequences of the research, i.e., the primary design of the measurements, laboratory tuning, and field applicability. Furthermore, the paper presents a series of field cases in which these techniques were used, to highlight the industrial applications of such a package of measurements.
The Effect of Operating Decisions on Peripheral Waterflood Cash Flow
Authors: Wayhan D.A.
Published: December 2007

A study of 20 Denver Basin peripheral waterfloods showed that the rate of waterflood oil recovery was influenced by the rate of water injection and by the water cycle volume; but principally it was influenced by waterflood timing. Discussed here are the magnitude and relative influence of these factors on waterflood cash flow and present worth. present worth. Introduction

Peripheral injection is frequently chosen as the best Peripheral injection is frequently chosen as the best means to waterflood a reservoir because the peripheral wells contribute less to current income. Also, the peripheral wells are often advantageously located downdip from the oil column. Because of their structural position they may have experienced some water influx or may have had water originally present in part of the sand section. part of the sand section. On the other hand, a peripheral waterflood is especially sensitive to operating decisions made before and during the life of the waterflood. If there are several rows of producers to be stimulated by one row of injectors, a slow waterflood start or a low injection rate can result in severely delayed waterflood response at interior producers. If large volumes of injected water are removed at close offsets to injectors, further delay or even a stalled waterflood may result.

The many completed or essentially completed peripheral waterfloods in the Denver basin provide an peripheral waterfloods in the Denver basin provide an excellent opportunity to study waterflood experience and to see how decisions concerning the major operating alternatives - that is, waterflood timing, the injection rate, and the water-cycle volume - have influenced peripheral waterflood cash flow.

Waterflood Recovery

An earlier paper reported the results of an analysis of waterflood recovery data from 23 Denver Basin waterfloods (20 were peripheral-type floods). The analysis indicated that ultimate recovery was influenced by the timing of a waterflood - the earlier a waterflood is conducted after reservoir pressure reaches the bubble point, the higher is the ultimate recovery. The reduction in recovery was shown to be due to shrinkage effects as expressed in Eq. 1.

(1) where

Erwf = waterflood recovery efficiency, percent,

Cr = relative conformance, percent,

E =

(This is water-drive recovery efficiency from Arps et al., assuming no pressure drawdown.)

Bob = reservoir volume factor at bubble point,

Bowf = reservoir volume factor at waterflood start.

Eq. 1 indicates that waterflood recovery will be reduced significantly if the reservoir volume factor is high and if a waterflood is delayed until most of the primary oil has been produced. primary oil has been produced. Table 1 shows operating data from 23 waterfloods.

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