bluuebunny/crossref_metadata_2025 huggingface dataset:
Conditional Stochastic Moment Equations for Uncertainty Analysis of Flow in Heterogeneous Reservoirs
Authors: Li L. , Tchelepi H. A.
Published: December 2007

We assume that permeability is a random space function defined by its mean and covariance. The stochastic nature of the permeability description leads to uncertainty in flow-related quantities such as pressure, saturation, and production rate. We extended our statistical moment equation (SME) approach to accommodate conditioning. The conditional statistical moment equations (CSME) framework is a direct approach for quantifying the uncertainty in flow performance caused by uncertainty in the reservoir description. It is quite different from Monte Carlo Simulation (MCS). In MCS, the performance uncertainty is obtained through a statistical post-processing of flow simulations, one for each of a large number of equiprobable realizations of the reservoir description. We developed a CSME computational tool for flow in heterogeneous domains, which we use here to analyze the behavior of the second statistical moment of pressure and velocity in the presence of permeability measurements. We study the effect of both the number and spatial arrangement of available measurements on the computed variances of pressure and velocity. This numerical CSME tool allows us to quantify the value of existing and future information, and that helps in the evaluation of existing projects and in steering future developments. We present several examples that demonstrate how to choose the best sampling locations to obtain maximum reduction in prediction uncertainty. We compare our results with high-resolution MCS.
Reducing Gas-Production Decline Through Dewatering: A Case History From the Naturally Fractured Aguarague Field, Salta, Argentina
Authors: Aguilera R. , Conti J. J. , Lagrenade E.
Published: December 2007

The Aguarague field is located in the Devonian basin, northwest of the province of Salta, Argentina. Gas production is obtained from clastics of the Huamampampa formation through an intense network of natural macro- and microfractures. The reservoir is in a north/south-trending symmetrical anticline.

Five high-deliverability gas wells watered out between 1991 and 1994; as a result, the field gas production decreased substantially. This triggered a study in 1995 to try to find a means of extending the life of the reservoir. The study indicated that without any modifications, gas production could be expected to continue, at most, until 1999.

This paper describes how a detailed fracture characterization led to a dewatering project using gas lift, which significantly reduced the gas decline of the reservoir. The project also brought back to gas production some of the wells that had previously watered out. The 1995 forecast is compared with the actual production performance to date.
Estimating Multiphase-Flow Properties From Dual-Packer Formation-Tester Interval Tests and Openhole Array Resistivity Measurements
Authors: Zeybek M. , Ramakrishnan T. S. , Al-Otaibi S. S. , Salamy S. P. , Kuchuk F. J.
Published: December 2007

Multiphase flow and production cuts are affected significantly by relative permeabilities under reservoir conditions. However, their in-situ determination is practiced only in isolated instances, and these have used array resistivity logging. Although wireline dualpacker formation testers provide direct flow tests, analysis thus far has been confined to the determination of single-phase permeability and anisotropy. In this paper, we present a methodology to integrate the formation-tester pressure and water-fraction measurements with openhole array resistivity measurements to obtain zonal relative permeabilities of oil and water.

It has been demonstrated previously that the filtrate-invasion process, although uncontrolled, contains quantitative information about fractional flow. The sampling process is similar; it is described by the multiphase/multicomponent flow equations for which the initial condition is set by the invasion process. Geometrically, while the invasion process is largely cylindrical, the sampling process is not. To combine the two, we parameterize the invasion problem in terms of multiphase-flow properties and drilling-fluid loss and carry out a simulation exercise, including generation of resistivity logs. The fractional-flow parameters estimated by matching the observed resistivity logs are then used for modeling fluid sampling with a formation tester. Simultaneous matching of the simulation results with the observed water-cut and pressure data allowed for further refinement of the relative permeability curves. A field example of the application of this methodology will be discussed.
Pilot Testing of a New Generation of Induced Gas Flotation Equipment
Authors: Movafaghian Shaya , Chen James , Wheeler Stephen Scott , Guidry R. W
Published: December 2007

Induced gas flotation (IGF) technology is well-known in the oil industry for effectively treating produced water to meet environmental oil-in-water discharge requirements.

This paper presents technical considerations for development of a new generation of IGF units, a discussion of the process kinetics, actual operating data, and performance analysis of a full-sized, four-cell WEMCO* cylindrical depurator.

A pilot test program was developed and executed in collaboration with ChevronTexaco Overseas Petroleum on platformgathering-station Mike, located offshore in the Cabinda Province, Angola. Pilot data indicate that the flotation kinetic rate for oil removal from a four-cell cylindrical depurator is comparable with a conventional depurator.

Cylindrical depurator design captures the main technical advantage of conventional, mechanical IGF units for effective oil-particle flotation and offers the promise of fewer maintenance issues as well as viable alternatives for higher-pressure applications.

Field data validate theoretical predictions for the performance of the cylindrical depurator.
The Quality Map: A Tool for Reservoir Uncertainty Quantification and Decision Making
Authors: da Cruz Paulo S. , Horne Roland N. , Deutsch Clayton V.
Published: December 2007

The parameters that govern fluid flow through heterogeneous reservoirs are numerous and uncertain. Even when it is possible to visualize all the parameters together, the complex and nonlinear interaction between them makes it difficult to predict the dynamic reservoir responses to production. A flow simulator may be used to evaluate the responses and make reservoir management decisions, but normally only one deterministic set of parameters is considered, and no uncertainty is associated with the responses or taken into account for the decisions.

This paper introduces the concept of a "quality map," which is a 2D representation of the reservoir responses and their uncertainties. The quality concept may be applied to compare reservoirs, to rank stochastic realizations, and to incorporate reservoir characterization uncertainty into decision making (such as choosing well locations) with fewer full-field simulation runs.

The data points necessary to generate the quality map are obtained by running a flow simulator with a single vertical well completed in all the layers and varying the location of the well in each run to have good coverage of the entire horizontal grid. The quality of the horizontal cell in which the well is located is the cumulative oil production after a long production time.

The geological model uncertainty is captured by generating multiple stochastic realizations and building a quality map for each realization. The quality maps of all the realizations provide a distribution of quality values for each cell of the map grid. A mean quality map can be obtained by taking the expected value for each cell, and a map of quality uncertainty can be obtained by taking the standard deviation of the distribution for each cell.

If a loss function is specified, an L-optimal quality map can be generated by retaining, for each cell, the quality value that minimizes the expected loss. This map allows us to locate wells accounting for the geological uncertainty as well as for the risk profile of the decision maker.

The methodology for building the quality map is presented in detail, and the applications of the map are demonstrated with 50 realistic reservoir models.
A New Biopolymer-Free, Low-Solids, High-Density Reservoir Drilling Fluid: Laboratory Development and Field Implementation
Authors: Horton Robert L. , Tresco Kim O. , Dobson James W. , Bye Gry Kristvik , Knox Dave A. , Svoboda Charles F. , Foxenberg William E. , Green Taylor C.
Published: December 2007

Low-solids, brine-based reservoir drilling fluids (RDFs) are widely accepted as beneficial to optimizing compatibility with the completion design while minimizing fluid-related formation damage. Traditionally, the maximum density attainable with a low-solids fluid has been limited because of either the prohibitively high cost of the required base brine or the poor performance of viscosifying biopolymers in a dense, divalent cationic environment.

An RDF has been developed that exhibits unusually high quality rheological behavior in high-density calcium- and zinc-based brines without the aid of a biopolymer. The new fluid shows a unique shear-thinning rheological profile that features a relatively low high-shear-rate viscosity along with a relatively high low-shear-rate viscosity (LSRV). This behavior is highly unusual in high-density, brine-based RDFs. A result of this behavior is that effective hole cleaning is provided without generating excessive high-shear-rate viscosities that lead to excessive equivalent circulating densities (ECDs).

The first field trial of this fluid was on the reservoir section of Well 34/10 I-1-AH in the Gulfaks Satellites Development in the Norwegian sector of the North Sea. Fluid properties during pretesting, mixing, drilling, and completion of this section are detailed in this paper.
Reservoir Simulation Using Bottomhole Pressure Boundary Conditions
Authors: Kuniansky Joseph , Hillestad J. G.
Published: December 2007

This paper presents results derived from potential flow theory for single-phase flow in the region near an injection or production well. The relations obtained are directly applicable to reservoir studies where coarse grid systems, which cannot account for near-wellbore flow, are used to describe flow within the reservoir.

Near-wellbore effects have received only minor attention in the literature.1–7 This work concentrates on a general solution to this flow problem. Relations are derived for a system with one or two wells located in a rectangular area and for n wells located in an infinite area. The paper also gives a method that accounts for areal flow behavior near a wellbore in cross-sectional simulations. Comparisons of the analytical results with computer results using Peaceman's5 relationship for the effective wellbore radius of a simulator well show good agreement for cases where the wells are located at the block center regardless of the grid size or the position of the well block within the grid system. The paper also illustrates how pressure boundary conditions can be applied in cases where the wells are not located at the center of a grid block. The derived relationships are applicable for a simulator based on either five- or nine-point formulations.
Strategies for Sizing Particles in Drilling and Completion Fluids
Authors: Suri Ajay , Sharma Mukul M.
Published: December 2007

To minimize formation damage caused by drill-in and completion fluids, solids must be sized to satisfy two important criteria. First, they must be large enough to not invade the rock, and second, they must be small enough to form filter cake that effectively filters drill solids and polymers from entering the formation. These criteria, when used together with the model presented in this paper, quantitatively determine the particle size that should be used in drill-in fluids for a given formation permeability, overbalance pressure, and mud formulation.

A model is presented that estimates the depth and degree of formation damage caused by solids of widely different sizes present in drilling or completion fluids. The depth of damage and permeability loss is calculated after the invasion of the mud and also after flowback. The effect of the particle size distribution in the fluid, particle concentration, overbalance pressure, and permeability of the formation are studied. It is demonstrated that particle invasion and flowback processes are largely dependent on the particle size in the mud and the permeability of the formation. The results of the model are shown to agree well with mud filtration experiments.

To better estimate the particle size distribution in drill-in and completion fluids, different methods for measuring particle sizes were investigated. These results show that the measured particle sizes can vary over two orders of magnitude depending on the technique used and on sample preparation. Based on a comparative analysis of several samples, light-scattering techniques are recommended for measuring the particle size distribution. Recommendations for sample preparation are also provided.
Time Scaling of Rates of Produced Fluids in Laboratory Displacements
Authors: Laroche Catherine , Chen Min , Yortsos Yannis C. , Kamath Jairam
Published: December 2007

In a recent study,1 it was shown that the ratio of the flow rates of the produced fluids in an immiscible displacement can be used to identify geometrical and petrophysical characteristics of a reservoir. In this paper, we develop an extended version of this approach and apply it to displacements in 1D laboratory cores. Because of the possible importance of capillary effects, we derive asymptotic theories for the time dependence of the produced fluid ratio in the limits where capillary is negligible and where it dominates, respectively. Attention is paid to the capillary end effect at the outlet and to late times.

It is shown that the exponent in the power-law dependence of the relative permeability to saturation, near its residual value, can be determined from a segment of the curve of the outlet fractional flow sometime after breakthrough. The asymptotic predictions are verified by obtaining an analytical solution to the full problem, including end effects, for a model case corresponding to Burgers' equation. Solutions are obtained for both drainage and imbibition. Experimental results for the high-rate displacement of some gas/ liquids pairs are then reported. In agreement with the theoretical predictions, a power-law segment in the outlet fractional flow curve can be identified before capillary effects set in. The exponents obtained are discussed in terms of pore-scale models for gas/liquid displacement.
Split Full Tensor Discretization Operators for General Hexahedral Grids
Authors: Edwards Michael G.
Published: December 2007

A major assumption in many simulators is that the pressure equation always has a diagonal tensor. However, in many cases of practical interest, a full tensor matrix occurs. Three contributing factors that can give rise to a full tensor pressure equation are anisotropic media, upscaling (with cross-flow effects), and non-K-orthogonal structured and unstructured grids. The introduction of a full tensor approximation typically increases the support of the standard scheme on a logically rectangular grid from 7 to 27 nodes in 3D, which can increase 3D simulation costs by over 100%. In this paper, 3D full tensor operator splitting schemes are presented. These schemes maintain consistent full tensor approximations while only requiring diagonal tensor inversion.
New Numerical Schemes for Near-Well Modeling Using Flexible Grids
Authors: Ding Y. , Jeannin L.
Published: December 2007

Control-volume schemes are discussed for the modeling of vertical wells using flexible grids.

The main difficulty of well modeling in reservoir simulation is the problem of the difference in scale between the reservoir size (several kilometers) and the wellbore radius (several centimeters). In applications, although the wellbore boundary can be discretized using flexible grids, the gridblocks in the vicinity of the well are usually not small enough compared to the wellbore radius, and the gridblock sizes vary, usually geometrically, in the radial direction from the well. This kind of grid makes the commonly used linear approach (that is linear with respect to coordinates of physical space) inefficient for near-well flow modeling.

In this paper, new numerical schemes, based on logarithmic approach, are proposed to improve the linear approach for nearwell modeling. In particular, a multipoint and a two-point flux approximation scheme are presented. These schemes can reduce the calculation errors for the dominant "singular" well flow and consequently give good results. The proposed approach can be used for any kind of flexible grid for near-well modeling.
A Neural Network Model for Prediction of Liquid Holdup in Two-Phase Horizontal Flow
Authors: Shippen Mack E. , Scott Stuart L.
Published: December 2007

Accurately predicting the liquid holdup associated with multiphase flow is a critical element in the design and operation of modern production systems. This prediction is made difficult by complex phase distributions and the wide range of fluid properties encountered in production operations. Consequently, the performance of existing correlations is often inadequate in terms of desired accuracy and application range. This investigation focuses on the development of a neural network model, a relatively new approach that has been applied successfully to a variety of complex engineering problems. Data from five independent studies were used to develop a neural network for predicting liquid holdup in two-phase horizontal flow. A detailed comparison with existing empirical correlations and mechanistic models reveals that for this data set, the neural network model shows an improvement in overall accuracy and performs more consistently across the range of liquid-holdup and flow patterns.
History Matching Using a Streamline-Based Approach and Gradual Deformation
Authors: Gautier Y. , Nœtinger B. , Roggero F.
Published: December 2007

Reservoir engineers often have to deal with history-matching problems. This is time-consuming because of the many numerical simulations that have to be run and also because of the size of the models. Optimization, coupled with gradient-based methods, enables engineers to find efficiently a reservoir representation that respects all static and dynamic data. Nevertheless, for multiphase flow or for compositional problems, only relatively small models can be handled with a finite-volume flow simulator. On the other hand, streamline-based simulation provides accurate and fast estimates to various flow problems. Simulations can be performed on larger models than with a regular fluid flow simulator. Recently, streamline-based simulation has been used for history-matching problems. First, analytical gradients of production data with respect to a geostatistical parameterization have been computed for the tracer-flow case. The saturations along streamlines were moved using an analytical solution of the transport equation. This approach then has been extended to waterflood problems with varying boundary conditions.

In our method, we compute gradients of the production data, of the saturation, and of the pressure. We use a 1D numerical simulator to move the saturation along streamlines. This method is more general than when analytical calculations are used; it is more accurate for complex flow patterns. It also can be extended to take into account other parameters such as gravity. The major drawback is that it is more time-consuming; the cost for the computation of each gradient is slightly smaller than the cost of a simulation. Nevertheless, this cost can be dramatically decreased by computing multiple gradients at the same time on different processors using parallelism.

These gradients will be used to perform history matching using a nonlinear optimization package in conjunction with a geostatistical method, the gradual deformation method, enables the combination of multiple realizations of a permeability field and the continuous variation from one to another.

We will apply our new method to perform a history match on a large-scale 3D synthetic example of a waterflood with a complex injection history.
A Review of Permeability-Prediction Methods for Carbonate Reservoirs Using Well-Log Data
Authors: Babadagli T. , Al-Salmi S.
Published: December 2007

The prediction of permeability in heterogeneous carbonates from well-log data represents a difficult and complex problem. Generally, a simple correlation between permeability and porosity cannot be developed, and other well-log parameters need to be embedded into the correlation. The first part of this paper covers an extensive review of the existing correlations in the literature. The use of porosity and other petrophysical properties of rock in permeability prediction is discussed for carbonaceous rocks. This discussion also covers the usefulness of a wide variety of correlations developed using pore-scale (Kozeny-Carman, percolation, and fractal models) to field-scale models (well logs).

In the second part of the paper, a case study is presented. The data are obtained from a complex carbonate field in Oman. Conventional and nonconventional (mainly nuclear magnetic resonance, or NMR) well-log data are evaluated to seek the parameters reflecting a good correlation with permeability. After testing each independent variable against core permeability, the variables yielding the highest correlation coefficient (CC) are included in multiple regression analysis. Data collected from seven wells are used to obtain the permeability correlations for the whole field and for four geological units separately. The test of the correlations is achieved through the comparison of the estimated permeability values to core permeability. Finally, the correlations are compared with the core permeability of the eighth well (data from this well are not included in the development of the correlation) for validation. The correlations are obtained for the four geological units. Two of these units responded well to conventional well-log data; the other two units yielded reasonable correlations only with NMR log data.
Reservoir Modeling Methods and Characterization Parameters for a Shoreface Reservoir: What Is Important for Fluid-Flow Performance?
Authors: Jian F. X. , Larue D. K. , Castellini A. , Toldi J.
Published: December 2007

Fifty reservoir models were built by using seven different modeling methods and varying a combination of reservoir characterization parameters using experimental design. These 50 models were all subjected to unconstrained fluid-flow simulation with an active aquifer and limited peripheral waterflooding without history matching. The results show that oil recovery from existing wells at 95% water cut ranges from 29 to 34% in these 50 models despite the large apparent visual differences between them. However, there are large differences (some greater than 200%) in water-breakthrough time, water cut, and cumulative water production. The differences in oil recoveries and water cut among all models were found to be largely related to horizontal permeability heterogeneities perpendicular to the shoreline direction.

Experimental design indicated that there were statistically significant differences in flow-simulation results associated with the definition of reservoir quality trends, 3D facies trends, and variogram range and direction. Do more complex, geologically realistic models provide the best frameworks for predicting flow performance in sandy shoreface reservoirs with good well control? Some of the simplest models we constructed provided flow-simulation results similar to those of the most complex and soft-data-conditioned models. What we do observe, however, is that the more soft conditioning data and the more complex geologic models tend to give a restricted range in full-field flow performance.
Otter: A 21-Kilometer Subsea Tieback With Dual Electric Submersible Pumps
Authors: Horn Mark , Coudeville Frederic , Bespalov Eugene , Butcher Howard
Published: December 2007

The Otter field in the northern North Sea has been developed with three subsea production wells, each equipped with dual electric submersible pumps (ESPs). Dual ESPs were selected because they maximize well availability and minimize operating costs associated with workovers. The field is located 21 km from the host platform, making this development the longest subsea tieback with ESPs completed to date.

The equipment selected for the ESP system is described here, including downhole, subsea, and topside equipment. The rigorous testing program is also described, proving that ESPs could be successfully operated and controlled as well as receive data at such a distance from the variable-frequency drives.

The experience gained during the development and the operational philosophy developed for the Otter field will serve as a guide to future long-stepout or deepwater subsea developments by identifying critical components. Factors limiting the development of fields at greater stepouts are also discussed.

Conclusions on the steps required to implement a successful development and some of the pitfalls to avoid are listed in this paper.
Numerical Simulation of Mud-Filtrate Invasion in Deviated Wells
Authors: Wu Jianghui , Torres-Verdín Carlos , Sepehrnoori Kamy , Delshad Mojdeh
Published: December 2007

Understanding the spatial distribution of fluids in the near-borehole region caused by mud-filtrate invasion is necessary for the accurate petrophysical interpretation of wireline measurements acquired in deviated wells. This paper provides a sorely needed petrophysical and fluid-flow template that can be used to integrate several wireline measurements into a unique model of petrophysical parameters in the near-borehole region of deviated wells.

We simulate numerically the physics of mud-filtrate invasion in vertical, horizontal, and highly deviated overbalanced wells. The numerical algorithm is adapted from a general 3D multiphase-fluid-flow simulator that is widely used in large-scale reservoir applications. Checks of numerical consistency and accuracy are performed against one commercial reservoir simulator. Emphasis is placed on describing the influence of mudcake buildup on the mud-filtration process. We approach the latter problem by introducing an effective-flow-rate function that describes the evolution in time of the rate of invasion of mud filtrate into rock formations. Parametric representations of the flow-rate function are derived on the basis of previously published laboratory experiments of mud circulation.

A sensitivity analysis quantifies the influence of several geometrical and petrophysical parameters on the spatial distribution of mud-filtrate invasion away from the borehole wall. These parameters include relative permeability, capillary pressure, permeability anisotropy, dipping layers, and degree of hydraulic communication between adjacent layers. Our simulations reveal the character of invasion profiles in complex geometrical environments taking place under realistic petrophysical conditions. We show that standard pistonlike descriptions of mud-filtrate invasion, commonly used in well-log interpretation, can lead to inaccurate interpretations of wireline measurements. An example is presented of the use of our simulation technique by calculating the sensitivity of borehole electromagnetic induction measurements to specific conditions of mud-filtrate invasion in a vertical well.
An Integrated Reservoir Characterization Study Matching Production Data and 4D Seismic
Authors: Kretz Vincent , Ravalec-Dupin Mickaële Le , Roggero Frédéric
Published: December 2007

Our purpose is to evaluate the benefit of using time-lapse seismic in addition to production history for reservoir characterization. A new inversion methodology, based on the gradual deformation method (GDM), has been developed to simultaneously integrate different sources of information like 4D-seismic-related data and production data. This methodology was validated successfully on a geologically realistic 3D synthetic reservoir model.

An optimization procedure was developed to identify reservoir models consistent both with an initial 8-year period of production data and with 4D-seismic-related data. The procedure is based on two complementary numerical tools developed at the Inst. Français du Pétrole: the Fast Fourier Transform—Moving Average (FFT-MA) generator and the GDM. The first tool generates stochastic realizations for the reservoir model; the second tool allows us to perturb the realizations from a small number of parameters while preserving the spatial-variability model. The optimization process was repeated starting from different initial reservoir models. The predictive quality of the constrained reservoir models was estimated by comparing the simulated forecasts and the reference data for a second 8-year period of production data.

The proposed inversion method proved its efficiency for constraining geostatistical reservoir models to different sources of data. It is shown that conditioning reservoir models to saturation changes in addition to production data results in significant improvement in the reliability of production forecasts. The present study goes one step further than the study by Kretz et al.,1 which was dedicated to the integration of accurate gas-saturation data into the reservoir model. Because such accurate data are rarely available, we focus on a more realistic case: we estimate the usefulness of binary data, indicating the presence or absence of gas.
Numerical Studies of Gas Production From Class 2 and Class 3 Hydrate Accumulations at the Mallik Site, Mackenzie Delta, Canada
Authors: Moridis G. J.
Published: December 2007

The Mallik site represents an onshore permafrost-associated methane hydrate accumulation in the Mackenzie Delta, Northwest Territories, Canada. This study focuses on gas production at the Mallik site from hydrate deposits that are underlain by either a free-water zone (Class 2) or an impermeable boundary (Class 3). The production analysis was conducted with a numerical simulator that can model the nonisothermal CH4 release, phase behavior, and flow under conditions typical of CH4-hydrate deposits by solving the coupled equations of mass and heat balance. Accumulations with a CH4-hydrate saturation of at least 50% were studied. Dissociation was induced mainly by a combination of thermal stimulation and depressurization as hot fluids circulated between injection and production wells. The effects of salinity and of pressure changes at the wells were also accounted for. The production strategy resulted in a zero net water production. The simulation results indicated that the amount of CH4 released from the dissociating hydrate deposits is sensitive to the hydrate saturation, the initial temperature, the specific enthalpy, and the flow rate of the circulating fluids.
Slaughter Estate Unit CO2 Pilot - Surface and Downhole Equipment Construction and Operation in the Presence of H2S
Authors: Adams Gene H. , Rowe Hunter G.
Published: December 2007

This paper presents the material selection, construction procedures, safety devices, corrosion control and monitoring, and operational procedures necessary for successful compression, transportation, and injection of a gas stream containing 28% hydrogen sulfide. It also discusses various operational problems encountered during the 3-year project life.

Introduction

As Amoco's West Texas waterfloods in the San Andres formation matured, it became evident that they would reach their peak production levels and begin to decline in the early 1970's. It also became evident that recovery of original oil in place through primary and secondary means would be in the range of 25 to 45%. The large quantities of oil which would remain unrecovered led to considerations of tertiary recovery methods.Although much laboratory work had been done in studying tertiary recovery processes, it was recognized that only field testing in a reservoir environment could prove the economic viability of the various tertiary methods. Screening of possible recovery techniques led to the selection of the miscible displacement process as having the most promise in these reservoirs. A company-wide search was made in late 1970 for possible tertiary project sites, and several pilot sites were selected to test the various miscible agents.A portion of the Slaughter Estate Unit which had not been waterflooded was selected as a site for a pilot test of the CO2 miscible displacement process. Fig. 1 shows the location of the Slaughter field in relationship to the West Texas - eastern New Mexico area. Fig. 2 shows the location of the Slaughter Estate Unit within Slaughter field. Eight pilot wells were drilled from March through June 1972, and waterflood operations began in Nov. 1972. Peak secondary oil production was seen in mid-1973, and by mid-1976 a steady secondary decline rate was discernible.It soon was determined that at projected injection rates a reliable source of pure CO2 in sufficient quantities and a means of delivering it to the pilot site did not exist. There was, however, a feed gas stream to the Claus sulfur unit at the Slaughter gasoline plant, about 7 miles (11.3 km) from the pilot site, which consisted of approximately 72% carbon dioxide and 28% hydrogen sulfide. Investigations ascertained that there were no commercially available processes for completely separating the hydrogen sulfide and carbon dioxide in the Claus plant feed gas (hereafter referred to as acid gas). Further, laboratory tests showed that the displacement process using acid gas as a solvent was the same as when CO2 was used. Preparations were made, therefore, to compress the acid gas stream and to transport it through a transmission line to the pilot wellsite.Of course, there was never any consideration given at any time to the use of the acid gas stream as a miscible agent during full-scale field flooding. In any case it would have provided only a tiny fraction of the required volumes of CO2.

JPT

P. 1065^
Cubic Equations of State Applied to HT/HP and Highly Aromatic Fluids
Authors: Pedersen K. S. , Milter J. , Sørensen H.
Published: December 2007

Pressure/volume/temperature (PVT) data are presented for 38 reservoir fluids including fluids dominated by paraffins, heavy aromatic fluids with a significant content of C81+, and high-temperature/high-pressure (HT/HP) reservoir fluids. By properly taking into account the compositional differences, these fluid types can all be represented using a classical cubic [Soave-RedlichKwong (SRK) or Peng-Robinson (PR)] equation of state (EOS) with volume correction. The plus fraction is split into carbon number fractions and EOS model parameters assigned to each fraction. To keep the number of components at a manageable level, the carbon number fractions are lumped into pseudocomponents, each containing several carbon number fractions. Hydrocarbons as heavy as C200 are considered when splitting up the plus fraction. Neglecting the content of components heavier than C80 will give a false picture of the phase behavior of heavy aromatic fluids. Correlations are presented for Tc, Pc, and w as a function of molecular weight and density. Problems are experienced representing the thermal expansion of stable oils using a cubic EOS in the classical form. It is shown that this deficiency can be cured by introduction of a temperature-dependent volume correction term.
Thermal Behavior During Restart of Ultradeepwater Flowlines
Authors: Golczynski T. S. , Niesen V. G.
Published: December 2007

For subsea tiebacks in ultradeep water, restarting from shut-in conditions can pose significant flow-assurance issues, particularly with respect to hydrate formation. Achievable restart rates are a function of available hydrate inhibition and shut-in conditions. The overall chemical volume required is highly dependent upon the tieback type, length, and insulation level. Current practice is to evaluate alternate procedures, such as preheating the flowline to reduce warm-up times and chemical requirements.
Alkaline Injection for Enhanced Oil Recovery - A Status Report
Authors: Mayer E.H. , Berg R.L. , Carmichael J.D. , Weinbrandt R.M.
Published: December 2007

In the past several years, there has been renewed interest in enhanced oil recovery (EOR) by alkaline injection. Alkaline solutions also are being used as preflushes in micellar/polymer projects. Several major field tests of alkaline flooding are planned. are in progress, or recently have been completed. Considerable basic research on alkaline injection has been published recently, and more is in progress. This paper summarizes known Field tests and. where available, the amount of alkali injected and the performance results. Recent laboratory work, much sponsored by the U.S. DOE, and the findings are described. Alkaline flood field test plans for new projects are summarized.

Introduction and Past Technology

The history of alkaline flooding, dates back- to the early 1920's, with roots in the combination of reservoir engineering and chemistry. Understanding, the interaction of the injected alkaline chemicals with the reservoir oil, water, and rock is a chemical problem, while using the interactions to improve oil recovery is a reservoir engineering problem. Alkaline oil recovery has been attributed to oil/alkali interaction (called "emulsification"), to alkali/rock interaction (called "wettability alteration"), and to chemical precipitation caused by mixing of the injected alkaline solution with the hardness ions in reservoir water. Any or all of these mechanisms can operate in a particular application. Because of the interplay of these mechanisms, alkaline flooding is ail extremely complex oil recovery process and tends to be site-specific in terms of process design and dominant recovery mechanism. Some of the apparent differences in the use of alkali cited in the literature result from the site-specific nature of a process that uses different mechanisms to improve oil recovery in different reservoirs. For this reason, most of the disagreement in the literature can be explained by differences in the recovery processes active in an individual reservoir, Recognition of the individual mechanisms should allow profitable application of alkaline flooding to a wide range of reservoir types. The first attempt to bring together what was known about alkaline flooding was made by Johnson' in 1975. He summarized Field data that had been published and the technology as it then was understood. From 1975 through 1979, when this paper was first written, the number of field tests concluded and described, begun, or planned grew as did research on the processes involved. It became evident that alkaline flooding was not a simplistic technique for enhancing oil recovery but rather a very complex one. From 1979 through mid-1982, the number of field tests planned and initiated increased markedly. This increase is attributed to the favorable economics created by the U.S. DOE's Tertiary Incentive Program. During the program's life from Aug. 1979 through Jan. 1981, 41 alkaline flood projects were certified.

JPT

P. 209^
Reservoir Permeability Determination Using After-Closure Period Analysis of Calibration Tests
Authors: Benelkadi Said , Tiab Djebbar
Published: December 2007

Hydraulic fracturing generally has been limited to relatively low-permeability reservoirs. In recent years, the use of hydraulic fracturing has expanded significantly to high-permeability reservoirs. The objectives of fracturing low-permeability reservoirs and high-permeability reservoirs are defined by reservoir parameters.

The estimation of reservoir permeability, a variable of great importance in hydraulic fracturing design, is frequently unknown because either candidate wells do not flow or pretreatment pressure-transient testing is required. Consequently, Nolte et al.1 introduced a new method for adding after-closure fracturing analysis to the pretreatment calibration testing sequence that defines fracture geometry and fluid-loss characteristics. The exhibition of the radial flow is ensured by conducting a specialized calibration test called the minifalloff test. Using the theory of impulse testing and the principle of superposition, Nolte et al.1 developed a method that allows the identification of radial flow and, thus, the determination of reservoir transmissibility and reservoir pressure.

This work proposes a new method for determining reservoir permeability. The method also offers the potential for determining the average reservoir pressure. This procedure is based on the use of the pressure derivative, and it requires only one log-log plot for the identification of the radial-flow regime and the determination of reservoir parameters.

The application of the proposed method is demonstrated on real field data from calibration tests performed on several oil and gas wells. The reservoir parameters (particularly permeability) determined with this method are verified by comparison with results obtained from pressure-buildup tests. Other sources, such as core analysis, lend support to the permeability estimated with the proposed technique.
An Equation for Calculating Skin Factor Due to Restricted Entry
Authors: Odeh A.S.
Published: December 2007

Two publications give the skin factor due to restricted entry to flow at thewellbore. Restricted entry occurs when only part of the productive sand is opento flow. This can be caused by partial penetration or by perforating a portionof the sand. penetration or by perforating a portion of the sand. It isrecognized that in some cases restricted entry may be due to pluggedperforations or to insufficient number of perforations. This situation, thoughit will result in an additional skin factor, is not what is discussed in thisarticle. One of the publications gives the skin factor for three cases. Thefirst is for a partially penetrating well; the second is for a well producingfrom only the central portion of the productive interval; and the third is fora well in which several equally spaced intervals are open to flow. The secondpublication presents charts for estimating the skin factor when presents chartsfor estimating the skin factor when the open interval starts at eight differentlocations and covers a range of thickness of 20 to 200 ft. In this article skinfactor as a function of sand thickness, location of the open interval, and thewellbore radius is given in a general equation form:

ht 0.825 kH Sr = 1.35 ----- ---1 {1n ht -------- + 7) hp kV

kH - 0.49 + 0.1 1n h ---------- kV

.1n r - 1.95}, .............................(1) wc

where

Sr = skin factor due to restricted entry, ht = total sand thickness, ft (m), hp = length of perforated interval, ft (m), kH/kV = ratio of horizontal tovertical permeability, rwc = corrected wellbore radius, ft (m), and is givenby

0.2126(Zm/ht + 2.753) r = r e wc w

for y greater than 0, and rwc = rw for y=0,

y = distance between the top of the sand and the top of the open interval, and zm = distance between the top of the sand and the middle of the openinterval.

The relation between y, hp, and Zm is

Zm = y+hp/2...........................................(2)

Because of symmetry, Zm/ht 0.5. A plot of rwc/rw vs. Zm illustrating thesymmetry is shown in Fig. 1.

Discussion of Eq. 1

The radius of drainage rd does not appear in Eq. 1. This is because sr isvery insensitive to rd. For example, an increase in rd from 330 to 6,600 ftincreases Sr from 43.38 to 43.50, when ht=300, y = 0, and rw = 0.25. The valueof sr is most sensitive to the ratio of the open interval to the sandthickness, and to the sand thickness. Comparison between sr values calculatedby Eq. 1 and read from Refs. 1 and 2 is given in Fig. 2. The comparison isgood, and Eq. 1 is adequate for engineering calculations. The use of Eq.1 isillustrated by the following example. Calculate Sr when ht=200 ft, hp=40 ft, rw= 0.25ft, and y=80ft.

P. 964
An Efficient Discrete-Fracture Model Applicable for General-Purpose Reservoir Simulators
Authors: Karimi-Fard M. , Durlofsky L. J. , Aziz K.
Published: December 2007

A simplified discrete-fracture model suitable for use with general-purpose reservoir simulators is presented. The model handles both 2- and 3D systems and includes fracture-fracture, matrix-fracture, and matrix-matrix connections. The formulation applies an unstructured control volume finite-difference technique with a two-point flux approximation. The implementation is generally compatible with any simulator that represents grid connections by a connectivity list. A specialized treatment based on a "star-delta" transformation is introduced to eliminate control volumes at fracture intersections. These control volumes would otherwise act to reduce numerical stability and timestep size. The performance of the method is demonstrated for several oil/water flow cases including a simple 2D system, a more complex 3D fracture network, a localized fractured region with strong capillary pressure effects, and a model of a strike-slip fault zone. The discrete-fracture model is shown to provide results in close agreement with those of a reference finite-difference simulator in cases in which direct comparisons are possible.
Marlin Failure Analysis and Redesign: Part 1 — Description of Failure
Authors: Bradford D. W. , Fritchie D. G. , Gibson D. H. , Gosch S. W. , Pattillo P. D. , Sharp J. W. , Taylor C. E.
Published: December 2007

This is the first of three related papers that describe the actions of an incident-investigation team formed to evaluate the failure of Well A-2 on the Marlin tension-leg platform (TLP). This paper outlines several possible failure modes and narrows the field of candidate failure modes to a small subset by deduction from both analysis and physical evidence. The application of these results and analytical techniques, as incorporated into the redesign of the subsequent completions, is addressed in the second paper of the series. The third paper discusses real-time monitoring of the redesigned completions.

The Marlin field is located in the Gulf of Mexico, Viosca Knoll Blocks 871/915, and was originally intended to be produced from a TLP by means of five predrilled dry-tree penetrations. First production from Well A-2 began in November 1999. Shortly thereafter, a minor but persistent tubing leak occurred. Between 7 and 20 November, Well A-2 was alternately flowing and shut in, depending on the shakedown of surface equipment and pipeline availability. On 20 November, the casing pressure jumped to shut-in tubing pressure, signifying a major tubing failure.

This paper describes the actions of an incident-investigation team formed to evaluate the failure of Well A-2. Possible failure modes investigated by the team include:

Helical buckling of the production tubing, with or without the combined loss of a tubing centralizer. Crushing of the tubing by ratcheting displacement from a failed centralizer. Lateral deflection of the subsea wellhead. Collapse of the production (and/or intermediate) casing onto the tubing because of one or a combination of the following. Hydrate formation outside the intermediate casing owing to gas migration from a shallow hydrocarbon zone with subsequent dissolution during initial production. Nonuniform loading of the production casing because of the geometry of the submudline packoff tubing hanger (POTH) slips. Leak in a production-casing connection. Annular fluid expansion (AFE). Formation of a heat pipe in the production tubing by production casing/riser annulus. Casing wear on the intermediate casing. Excessive initial pressure resulting from setting the casing hanger seal assembly in the subsea wellhead. Inadequate performance of the tubing or casing caused by either an incorrectly run or an inadequately manufactured joint.

Deducing from both analysis and physical evidence, the current installment will narrow the field of candidate failure modes to a small subset. Applying these results and analytical techniques, as incorporated into the redesign of the subsequent completions, is addressed in the second paper of the series.1 The final paper describes the implementation of the redesign as an insulatedtubing completion.2