bluuebunny/crossref_metadata_2025 huggingface dataset:
Characterization of Mixed-Wettability States in Oil Reservoirs by Atomic Force Microscopy
Authors: Basu Subhayu , Sharma Mukul M.
Published: December 2007

A new technique is described for directly measuring the capillary pressure required to rupture brine films on mineral surfaces. These measurements provide direct evidence for the creation of mixed-wettability states in oil reservoirs. In addition, the measurement of the critical disjoining pressure allows us to observe systematic variations in wettability as the capillary pressure is increased. The effect of brine salinity, pH, surface charge, and surface curvature have been quantified. Results for two reservoirs, one from Texas (Moutray) and another from Alaska (Prudhoe Bay), are presented.
A Method for Blowout-Rate Prediction for Sour-Gas Wells, Oldenburg Fields, Germany
Authors: Kikani Jitendra , Schwarz Heinrich , Graute Johannes
Published: December 2007

In view of the toxicity of H2S, sour-gas production has to be carefully planned for safe operation. For the determination of safe evacuation distances in the unlikely event of an accident, well-blowout conditions had to be investigated. A methodology for predicting blowout rates from sour-gas wells in the south Oldenburg area in Germany is presented. Flow under sonic conditions, wellbore dynamics, reservoir capacities and their interdependencies control the fluid movement. Generally the blowout rates have been calculated by superimposing reservoir and tubing performance curves (based on steady-state correlations). This approach predicts lower short-term transient rates than actually occurs. A finite-element pipe-rupture model for ultrashort-term transient rate calculations is used. A coupling mechanism between these results and a reservoir simulator with a steady-state vertical-flow-performance correlation is then defined. A time-based switching criterion is determined iteratively for each situation when the flow goes subsonic, and traditional well outflow models can be used.
A Method for Improving Line Successive Overrelaxation in Anisotropic Problems-A Theoretical Analysis
Authors: Watts J.W.
Published: December 2007

A recent paper describes a method of improving the convergence rate of line successive overrelaxation (LSOR) in anisotropic problems. That paper presents computed results showing the method to cause dramatic improvements, but includes no theoretical analysis of the method.

This paper offers such an analysis, explaining mathematically how the method works and why it has the effect it does. In doing so, it clears up, at least partially, two important uncertainties left by the previous paper - when to use the method and how to arrive at an optimal extrapolation parameter.

Briefly, the analysis shows that the method removes the components of certain eigenvectors from the solution vector. As shown by the analysis, sometimes this removal causes a tremendous improvement in the rate of convergence and at other times it has no effect. This indicates, in most cases, whether or not to use the method.

Furthermore, the analysis shows that in certain simple problems the method is really a special case of LSOR. In these cases, the optimal extrapolation parameter can be calculated exactly. In other parameter can be calculated exactly. In other cases, it can be estimated using the same techniques as used with LSOR.

Introduction

One step in the calculations involved in reservoir simulation is the solution of a large set of simultaneous equations. Often this solution is the most time-consuming part of the simulation.

There are several methods used for solving these equations. One of the more common of these is line successive overrelaxation or LSOR. A recent paper describes a way to accelerate the convergence rate of LSOR. That paper shows the modified method, called LSORC, to be very good in an anisotropic case, but no better than LSOR in an isotropic case.

Briefly, LSORC consists of LSOR, with the lines oriented along columns, combined with a correction made by columns. This correction is made in such a manner that the sum of residuals in each column of mesh points is forced to zero.

In this paper we analyze LSORC as applied to a homogeneous but not necessarily isotropic Neumann problem. We show that the correction made using problem. We show that the correction made using LSORC removes the components of certain eigenvectors of the LSOR iteration matrix from the solution vector. Removing the components of these eigenvecton eliminates the effects of their associated eigenvalues on the rate of convergence. In isotropic cases these eigenvalues have little or no effect on the convergence rate, so no improvement is obtained. In anisotropic cases they determine the rate, and removing their effects causes large improvements in convergence rate.

This analysis clears up two points not covered in the original paper. First, it helps to determine when LSORC should and should not be used. Second, it shows that LSORC is really a special form of LSOR. Therefore, methods used to estimate an optimal extrapolation parameter for LSOR apply to LSORC as well.
Probabilistic Drilling-Cost Estimating
Authors: Kitchel B. G. , Moore S. O. , Banks W. H. , Borland B. M.
Published: December 2007

Risk analysis has become an integral part of the decision-making process in the petroleum industry. Petroleum engineers, geoscientists, and project managers use risking tools to evaluate the economic viability of both exploration and development projects.

Conoco drilling engineers have combined a drilling-cost spreadsheet with a forecasting and risk-analysis program to predict the range of both cost and days necessary to drill a well. The model uses risk analysis and incorporates Monte Carlo simulation along with regional cost data to generate drilling cost and time requirements for a well. Using this model, the Conoco drilling engineers evaluate multiple drilling alternatives effectively. Subsequently, the drilling engineers' more informed risk-related recommendations aid management in the decisionmaking process of drilling a prospect or developing a project.

This paper describes the spreadsheet and the risk-analysis program used to generate the range of costs and days for a given well. In addition, the paper offers an example of the output data generated from the programs with an interpretation for a sample well.
Laboratory Studies of Fines Movement in Gravel Packs
Authors: Jennings A. R.
Published: December 2007

Most high-permeability, high-deliverability, unconsolidated, and loosely consolidated sandstone formations require gravel packing as part of the completion procedure. The gravel packs are designed to allow the soft formations to produce sand-free at economical production rates. Techniques and procedures used for gravel-size selection are typically based on criteria that have been used by the industry for more than 20 years.

Simple laboratory flow tests using clean gravel columns and fines from a variety of formations, however, indicate that existing gravelsize-selection guidelines are too conservative. Although the gravels selected are very efficient in preventing formation fines from entering the pack, the buildup of silt and fines at the gravel/formation interface can cause quick degradation of the effective permeability through the pack.

Improvements in gravel-pack life can be obtained by using gravel with higher initial permeability, either by increasing the average size of the gravels used (i.e., larger sand grains) or through the use of more spherical particles (synthetic gravel). The laboratory tests reported in this paper suggest that both alternatives can be considered in gravel-pack operations. It is a further premise of this paper that sufficient improvements have been made in gravel-pack procedures in recent years to allow effective placement of the proposed higher-permeability gravels.
Compressibility Effects on Transient Gas Pipe Flow
Authors: Mouser Gerald F. , Govier J.P.
Published: December 2007

Methods of iterative solution for the partial-differential equations governing the transient flow of gases in pipelines are obtained by using the method of characteristics and linear finite-difference techniques. Solutions are developed for (1) a constant gas compressibility factor throughout transient conditions, and (2) a variable gas compressibility factor at constant temperature, dependent upon pressures encountered during transient flow. Theoretical studies are made to compare results using both approaches for pipelines operating at various constant flowing temperatures. Results show greater differences between the two methods at lower values of flowing temperature due to the more rapidly changing compressibility factor as a function of variable pressure.

Introduction

The partial-differential momentum and mass equations describing transient gas pipe flow have been solved by various numerical methods. Among the techniques frequently employed in recent studies are implicit finite-differences and the method of characteristics. While these studies have been concerned with the numerical techniques and stability criteria required in transient flow solutions, few investigations have examined the effect of a variable gas compressibility factor on transient behavior. The purpose of this study is to develop and apply the numerical equations of transient gas pipe flow based on (1) a constant gas compressibility factor evaluated at the average of inlet and outlet pressures at initial time, and (2) a gas compressibility factor completely dependent upon the gas pressures encountered in the pipeline during steady- and unsteady-state flow. For both approaches, digital computer solutions of the partial-differential equations describing gas pipe flow are made possible by application of the characteristics transformation and linear finite-difference approximations. The theoretical results, based on both constant and variable gas compressibility, are compared graphically for various transient flow conditions with particular emphasis placed upon temperature effects. Numerous limiting assumptions are required in the development of any steady- or unsteady-state flow equations. In this study, the following assumptions are made.
Incorporating Seismic Attribute Maps in 3D Reservoir Models
Authors: Behrens R. A. , MacLeod M. K. , Tran T. T. , Alimi A. O.
Published: December 2007

We introduce a new geostatistical method to incorporate seismic attribute maps into a three-dimensional (3D) reservoir model. The method explicitly honors the difference in vertical resolution between seismic and well-log data. The method, called sequential Gaussian simulation with block Kriging (SGSBK), treats the seismic map as a soft estimate of the average reservoir property. With this method, the average of the cell values in any one vertical column of grid cells is constrained by the value of the seismic map over that column. The result is a model that contains vertical variability driven by well logs and the vertical-variogram model and spatial variability driven by the seismic map and the areal-variogram model.
A Single-Phase Wellbore-Flow Model for Horizontal, Vertical, and Slanted Wells
Authors: Ouyang Liang-Biao , Arbabi Sepehr , Aziz Khalid
Published: December 2007

In this paper, a single-phase wellbore-flow model is presented that incorporates not only frictional, accelerational, and gravitational pressure drops, but also the pressure drop caused by inflow. The new model is readily applicable to different wellbore-perforation patterns and well completions, and can be easily incorporated into reservoir simulators or analytical, reservoir-inflow models.

It is found that the influence of either inflow or outflow depends on the flow regime present in the wellbore. For laminar wellbore flow, wall friction increases because of inflow but decreases because of outflow. For turbulent wellbore flow, inflow reduces the wall friction, whereas outflow increases the wall friction. New wall-friction-factor correlations for wellbore flows have been developed that can be applied to determine the wall-friction shear and the frictional pressure drop for either inflow (production well) or outflow (injection well) and for either laminar or turbulent flow regimes.

Calculation results show that the accelerational pressure drop may or may not be important compared with the frictional component, depending on the specific pipe geometry, fluid properties, and flow conditions. It is recommended that the new wellbore-flow model be included in wellbore/reservoir coupling models to achieve more accurate predictions of pressure drop and inflow distribution along the wellbore, as well as the well production or injection rates.
Simulation System Provides Unique Training Method for the Oilfield
Authors: Beck Kent , Schwendemann Ken
Published: December 2007

Today's oilfield service environment has undergone significant change from that which existed 10 years ago. Integrated services and turnkey operations are becoming the norm for the industry, and oilfield service companies are finding themselves linked with operators and contractors in long-term service contracts that would never have been considered in the 1980's.

While these new alliances may prove to be the catalysts for energizing economic growth in the oilfield, they bring with them their own set of operational problems. For example, the integrated solutions approach requires that all parties have a thorough understanding of overall economic and operational project parameters as well as a defined area for which each must take responsibility. Therefore, to meet the demands of the integrated solutions concept, "the partners" must be able to assess all project needs properly so that the solution provided accomplishes the economic and operational goals for all involved. Each must have a detailed technical understanding of a wide variety of equipment, systems, and available resources. This is the area in which a major drawback to the integrated solutions concept often occurs—it has been difficult to provide a fast, efficient method to keep users abreast of the continuing enhancements to a technology that already appears to be state of the art! Additionally, development of unique systems often results from the combined efforts of integrated teams, and to ensure that the systems will provide the expected results, it is equally as important to be able to provide training for the personnel that are responsible for the day- to-day use and maintenance of the new systems.

In this paper, we will discuss a unique simulator that can resolve the training needs that have surfaced as a result of the rapidly changing operational concepts in the oilfield environment. We will present the concepts of the equipment simulator and capabilities of the global simulator methodology, and we will use an actual case history to describe in detail how the equipment simulator was used offshore on a recent well-test job in the Gulf Coast area to introduce a new well-test tool and to train a new design engineer.

With this information, we conclude that the use of the simulator will provide unparalleled training support for oilfield equipment and system applications and facilitate efficient development of integrated solutions for oilfield projects.
A Case History of the Postle Area-Computer Production Control and Reservoir Simulation
Authors: Irwin R.A. , Tucker C.W. , Schwartz H.E.
Published: December 2007

The Postle Area Computer Control Operation (PACCO) handles 95 oil wells, 45 water injection wells, and 10 water supply wells about 300 miles from the control computer. After a year's operation, the system showed itself to be highly satisfactory and effective, and pleasing to everyone - whether in operations, engineering, accounting. or management.

Introduction

Oil reserves were discovered in 1958 in the Pennsylvanian Age sands in the Postle Area of Texas County, Okla., by Republic Natural Gas Co. Step-out wildcats and development drilling established additional production and by 1960 five separate fields were identified. Subsequent development has gradually coalesced these fields to form a major producing area called the Postle Area, located near the center of the Oklahoma Panhandle (Fig. 1). This area now includes 38,000 productive acres and produces approximately 27,000 bbl of oil per day and 35 MMcf of gas per day from 332 producing wells. Five pressure maintenance units are in operation and are currently injecting 70,000 BWPD. Two additional pressure maintenance units are being formed.

A computer production control and data acquisition system operates 95 oil wells, 45 water injection wells, 10 water supply wells, five central tank batteries, two production test satellites and four water injection stations in four of the five units. The control computer is located in Oklahoma City, approximately 300 airline miles southeast of the producing properties.

Reservoir simulator model studies were used to monitor project performance, design a pressure maintenance program, and change the operational guidelines for a second project. They are expected to result in a 15 percent increase in ultimate oil recovery. The use of computers, of the digital reservoir simulator model, and of the computer production control and data acquisition system has afforded optimum project management of reservoir performance and operations.

In 1962, when development was approximately 20 percent complete, Mobil Oil Corp. acquired the Republic Natural Gas Co.'s acreage, which is a significant portion of the oil-productive acreage in the Postle Area. The following is a discussion of the ensuing exploitation of the five major Pennsylvanian Age oil-bearing sands underlying the Postle Area and the computer production control and data acquisition system as it was applied in the Postle Area.

Geology

The Postle Area is located in the southern portion of the Hugoton Embayment of the Anadarko basin in Texas County, Okla. The Pennsylvanian Age sands in this area underlie a portion of the Permian Age Hugoton gas field.

Editor's note: This paper is a combined version of the original manuscripts of "A Review of Postle Area - Development, Unitization, Pressure Maintenance and Computer Applications," by R.A. Irwin, C.W. Tucker, and H.E. Schwartz, Jr.; and "Computer Production Control and Data Acquisition as Applied in Postle Area," by H.E. Schwartz, Jr.
Prediction of Petrophysical Parameters Based on Digital Video Core Images
Authors: Oyno Lars , Tjetland B. G. , Esbensen K. H. , Soiberg Rune , Scheie Aase , Larsen Tore
Published: December 2007

Core-slab photography is a common way to document geological information from cores. Past practice has been to photograph core slabs with ordinary cameras that produce paper photographs. The presented method retrieves petrophysical properties from high-resolution digital video core images.

The procedures described in this work are based on video images (standard RIO/B camera) of cores taken with a digital recording system. The system is able to record in both visible and UV light at different illumination angles, store images, compress/decompress images, and display one or several images as a continuous long core. The seamless core image is marked with depth scale and can be scrolled, scaled, and zoomed. Facilities for correlation with other related data, such as wireline logs, discrete core data, and microscopy images, are also included in the system.

We used homogenous dry core plugs from three North Sea oil fields in this work. We recorded images of plug surface, together with conventional core-analysis data (i.e., porosity, gas permeability, average grain size, and mineralogy). The new method is based on processed digital images: light/shadow patterns are obtained by use of asymmetric, low-angle illumination in the green channel. Texture spectra of the rock material are obtained by dedicated image-analytical processing of these gray-scale images and by detecting textural features by use of a unique set of specially designed texture filters. We then calibrate these spectra with respect to measured petrophysical parameters by use of multivariate calibration [partial least squares (PLS)-regression]. Multivariate calibration is based on a set of representative training images, selected to span representative ranges of the intensive petrophysical parameters being modeled. On the basis of this calibration model, similar gray-level video images from new, unknown core sections (with geologically similar fades) are used to estimate properties of the core material by PLS-prediction. In this study it has been possible to model porosity, gas permeability, and average grain size (ORZ) of different formations with a relatively high accuracy and precision.

PLS-modeling/-prediction is a strict empirical calibration procedure. The present method is critically dependent upon a thorough, geologically well-documented training data set. Results show that the method is capable of predicting a continuous log of these three petro-physical parameters based on core images calibrated against a set of routine laboratory core-analysis data taken at discrete intervals for a particular formation. The advantages of the new method are rapid and cost-efficient methods for prediction of petrophysical parameters, particularly from slim cores, and improved integration of geological records with wireline data. The method is proposed to be included in future routine laboratory core analysis studies because of its low cost and ability to predict values continuously along the core.
Problems in Interpretation of Pressure Fall-Off Tests in Reservoirs With And Without Fluid Banks
Authors: Kazemi Hossein , Merrill L.S. , Jargon J.R.
Published: December 2007

Secondary- and tertiary-recovery injection projects may cause fluid banks to form in the reservoir. Pressure fall-off testing is often used in hopes of determining the parameters for each side of the fronts that delineate such banks. A mathematical model was used to investigate the practicality of such an approach.

Introduction

Pressure fall-off testing consists of shutting in an injection well and measuring the surface pressure or preferably the bottom-hole pressure vs time. This test is the counterpart of a pressure buildup test in a production well. The analyses of the pressure-time data in both tests, therefore, are remarkably similar. Nonetheless, because of the,.jnjection mode of operation, pressure fall-off testing has some unique characteristics.

In secondary- and tertiary-recovery projects three major fall-off situations may arise: liquid injection, gas injection, and alternate gas and liquid injection. The first two cases can be subdivided as follows:

Liquid Injection Case

(1) Liquid injection before fillup,

(2) Gas injection in aquifers for storage,

Gas Injection Case

(1) Air injection as in in-situ combustion,

(2) Gas injection in aquifers for storage,

(3) Gas injection for pressure maintenance,

(4) Gas injection in miscible displacement,

(5) Gas injection in gas cycling.

From this classification we learn that the mathematics of pressure fall-off testing must account for multiphase flow in many complex situations. Fortunately, numerical methods and computers have made the task of simulating such situations fairly simple and economical. However, to interpret actual fall-off test data from the field is still very difficult. The main problem is the nonuniqueness of the situations that give rise to nearly identical pressure fall-off behavior. The analysis of pressure-time data from a pressure fall-off test yields information about the interwell transmissibilities, interwell average pressure, and skin factor. Fall-off testing has also been used to track the movement of the burning front in in-situ combustion, to locate the position of the outer radius of a water bank, and to help in calculating formation damage depth. In general, "front tracking," or locating discontinuities by pressure fall-off is very intricate and must be used with extreme caution. Often, the front or discontinuity cannot be detected, and what appears to be a front or a transmissibility change (damage or improved zone) on the fall-off curve is actually a reflection of some other phenomenon. Considerable care must also be taken in determining transmissibilities from the slopes of the straight-line segments. As we will show, there are several factors besides the transmissibility that can influence these slopes. Afterflow (wellbore storage) invariably occurs in fall-off testing and in many cases can cause misinterpretation of data. Recent advances in this area have laid the foundation for understanding such problems.
Electronically Enhanced Remote-Actuation Systems Improve Deepwater Completions and Capabilities
Authors: Hopmann Mark , Dodd P. L.
Published: December 2007

With offshore rig demand at a premium and costs often exceeding U.S. $100,000/D, the economics of developing burgeoning deep-water arenas is closely tied to technologies that expedite production and reduce rig time. This paper describes a new, mud-pulse-frequency-based communication technique that actuates and manipulates downhole tools equipped with onboard electronics. The down-hole tools (which may include permanent or retrievable packers and sliding sleeves) are programmed at the surface to recognize one of 16 discrete actuation commands from a computer-controlled, portable terminal unit. Once in position, the tools are actuated upon receipt of a specific command sent from the portable terminal unit. As many as 16 devices can be actuated independently of one another in a single wellbore; and, because the system is independent of absolute pressure in the tubing, there is no need to install, for example, a tubing plug to set a packer.

By using packers equipped for electronically enhanced remote actuation, days of rig time can be saved by accelerating the completion cycle. Sliding sleeves equipped with the new technology can be remotely shifted without using coiled tubing or wireline. Electronically enhanced remote actuation allows for reduction, and in some cases total elimination, of common well-intervention operations associated with getting the initial completion in the ground. The resulting savings in operating expense and overall completion cost can be substantial, as has been proved in several recent deepwater applications.
Pressure Maintenance Operations in the Sharon Ridge Canyon Unit, Scurry County, Tex.
Authors: Lacik Harold A. , Black Joseph L.
Published: December 2007

The Sharon Ridge Canyon Unit is a pressure maintenance project using fresh surface water injected on a peripheral pattern. Canyon Reef limestone of Pennsylvanian age, occurring at approximately 6,700 ft, comprises the producing reservoir. The original producing mechanism was that of an undersaturated solution-gas drive. Rapid pressure decline and the threat of climbing gas-oil ratios pointed toward the need for pressure maintenance. Performance to date under the influence of water injection has been very encouraging. During six years of water injection, the volumetric average reservoir pressure has increased 338 psi, from 1,583 to 1,921 psi. The producing gas-oil ratio has been reduced from about 1,300 to about 900 cu ft/bbl. Before water injection, it was necessary to withdraw approximately 2.3 reservoir bbl in order to place 1 bbl of oil in the stock tank. Now, 1 bbl of stock-tank oil requires a withdrawal of only 1.8 reservoir bbl. Peripheral portions of the reservoir which have experienced encroachment by the injected water have performed better than predicted. Based on this history and recovery predictions, ultimate recovery as a result of this water injection will be at least 50 per cent of the original oil in place. This is twice the predicted recovery without pressure maintenance.

Introduction

With the completion of Humble Oil and Refining Co.'s R. E. Bishop 1 (now known as Tract 35, Well 1) in March, 1949, the Sharon Ridge Canyon field was discovered. This field is located approximately 20 miles southwest of Snyder, Tex., and its Pennsylvanian reef reservoir was divided from the Kelly Snyder and Diamond "M" fields by means of arbitrary lines. In Nov., 1951, the Sharon Ridge Canyon field was combined with the Diamond "M" field. Less than two years after the discovery well had been completed and with the field only 75 per cent developed, the operators met and formed the "Sharon Ridge Canyon Engineering Committee". A great amount of work and study directed toward a conservation program resulted in the formation of the Sharon Ridge Canyon Unit, with 100 per cent of the operators signing the agreement. On May 1, 1955, unitized operations commenced with a peripheral water-injection pressure maintenance program.

JPT

P. 645^
Ultimate Resistance Against a Rigid Cylinder Moving Laterally in a Cohesionless Soil
Authors: Reese Lymon C.
Published: December 2007

The ultimate resistance against a rigid cylinder which is moved laterally in a cohesionless soil is a function of the geometry of the cylinder and the properties of the soil. An approximate method is developed for computing this resistance and is tested against results of laboratory experiments. Satisfactory agreement between the method and experiment was obtained. Not only was the ultimate resistance against the cylinder measured, but careful measurements were made of the shape of the rupture surfaces. These measurements should allow the development of a more rigorous computation procedure.

Introduction

A critical aspect in the design of offshore drilling platforms is assuring the stability of the platform during a hurricane. The large horizontal loads from waves and wind make a severe loading condition. Piles are generally employed as the foundation since they can be effective in resisting both horizontal and vertical loads. Spuds are sometimes used with a mat foundation, where the spuds are designed principally to resist horizontal loads and the mat designed principally to resist vertical loads. The research reported in this paper is related to one aspect of the problem of laterally loaded piles or spuds in sand. The complete solution to the problem of the laterally loaded pile in sand would require the prediction of soil resistance against the pile as a function of pile deflection; only the ultimate resistance against short piles is considered in this paper. A considerable amount of additional research will be necessary to obtain a complete solution to the problem of the laterally loaded pile in sand; however, the work reported here should be useful as a guide in the performance of some of the additional research.

ULTIMATE LATERAL RESISTANCE AGAINST A LONG WALL IN SAND

To aid in the understanding of the theory which is developed for a cylinder, the theory for earth pressure against a wall is reviewed. In Fig. 1(a), a long wall of height H is shown embedded in soil. Soil resistance will develop as the wall is deflected, and the soil resistance will increase with deflection until some limiting value is reached. In this discussion, and those following, it is assumed that all points on the wall deflect equal amounts. A possible shape of the real curve which relates soil resistance to deflection is shown by the dashed line in Fig. 1(b); however, as a means of simplifying the discussion, an idealized curve (shown by the unbroken lines) is drawn. If such a wall as this were furnishing the horizontal support for an offshore structure, the dashed curve in Fig. 1 would be the information needed in performing a foundation analysis, with the idealized curve possibly being an acceptable substitute.

SPEJ

P. 355^
Laboratory Tests and Field Implementation of Gas-Drag-Reduction Chemicals
Authors: Li Ying-Hsiao , Chesnut G. R. , Richmond R. D. , Beer G. L. , Caldarera V. P.
Published: December 2007

Drag reduction in gas-transmission lines can be achieved by applying a thin chemical coating on the pipe inner surface to reduce friction between the flowing gas and pipe wall. Newly identified molecules used for gas-drag reduction can strongly bond to metal surfaces and form a smooth film to mitigate gas turbulence at the gas/solid interface. Effective gas-drag reducers have properties similar to corrosion inhibitors and lubricants or a combination of both. Fatty acids, oxylated fatty acid amines, and/or amides with carbon numbers between 18 and 54 can provide this type of behavior.1 The desired scenario is based on positively charged amine and amide functional groups providing strong binding to the metal surface and the long-chain hydrocarbon part serving as a compliant or lubricating surface to mitigate turbulence at the gas-phase boundary.2

A field test using Nalco 945 corrosion inhibitor at High Island 24L [a 7.625-in. inside diameter (ID) and 6.25-mile-long gas line from an offshore platform to the inland facilities in Sabine Pass, Texas] demonstrated gas-throughput improvement up to 20% at its peak performance. The improvement can be defined either as a reduction in pressure drop at a constant flow or as a flow-rate increase at a constant pressure drop. In this case, the gas-drag reducer resulted in a decrease in pressure drop from 180 to 150 psi and an increase in flow rate from 50 to 52 MMscf/D, while maintaining discharge pressure at about 840 psi. Its effectiveness peaked at the third week after one injection treatment, and then gradually tapered off. Benefits lasted more than 2 months.
The Differentiation Method in Rheology: IV. Characteristic Derivatives of Ideal Models in Couette Flow
Authors: Savins J.G. , Wallick G.C. , Foster W.R.
Published: December 2007

The dual differentiation-integration method of rheological analysis is applied to Couette flow. Using machine processing techniques, a spectrum of characteristic derivative functions for a variety of ideal Generalized Newtonian and viscoplastic models has been developed: As for the case of Poiseuille flow the functions for Generalized Newtonian models as a class are strikingly different from the corresponding functions for the class of viscoplastic models. It is shown that this dual scheme of analysis is a highly sensitive analytic method for determining the applicable range of a rheological model. The unique characteristics of this function in the case of viscoplastics may lead to a more precise detection and evaluation of the yield point or yield stress in these materials.

Introduction

It has been shown that the dual differentiation- integration method of analysis is a discriminating and flexible method for interpreting flow behavior and determining the applicable range of a particular model from Poiseuille flow experiments. In the preceding paper the basic equations governing the Couette flow experiment were reviewed and the significance of changes in boundary conditions on data analysis in the case of the viscoplastic discussed. In this paper the dual method of analysis is applied to Couette flow using the suites of rheological models considered previously.

THEORETICAL CONSIDERATIONS

NEWTONIAN LIQUID

f (p) = p......................(1)

Substituting Eq. 1 in Eq. 4 of Ref. 3 and integrating yields

Dv = p1........................(2)

where Dv is the nominal shear rate at R1, viz:R2, and B is the radii ratio. Here R1

............(3)

...................(4)

....................(5)

GENERALIZED NEWTONIAN SYSTEMS

Odd Power

..........(6)

Integration after substitution of Eq. 6 in Eq. 4 of Ref. 3 yields

......(7)

and hence,

...(8)

........(9)

= .............(10)

Series (General)

............(11)

SPEJ

P. 177^
Experimental Investigation of Frictional Pressure Losses in Coiled Tubing
Authors: Azouz Idir , Shah S. N. , Vinod P. S. , Lord D. L.
Published: December 2007

This paper presents an experimental investigation of tubular frictional pressure loss in coiled tubing (CT) and straight sections of seamed and seamless tubing. Fluids investigated include water, linear guar gum and hydroxypropyl guar (HPG), and borate-crosslinked guar gum and HPG, under conditions typically encountered in many CT field applications. The equipment used includes a system of one 1000-ft and two 2000-ft CT reels that can be arranged to provide total CT lengths of 1,000, 2,000, 3,000, 4,000, and 5,000 ft. The system also includes straight sections of seamed and seamless tubing with the same nominal diameter (1½ in.) and wall thickness (0.156 in.) as that of the CT. The investigation focuses mainly on the effects of CT curvature, tubing seam, fluid pH, and shear history on frictional pressure loss. Results obtained with water indicate that curvature, as well as the seam inside the CT, significantly affect the frictional pressure losses. Results obtained with various polymer solutions and gels, however, suggest that tubing curvature has a more significant effect on the frictional pressure losses than the tubing seam. Moreover, it is observed that, for borate-crosslinked HPG, the pressure gradient is dependent on both the fluid pH and the length of CT across which it is measured. However, for borate-crosslinked guar gum, the pressure gradient is a function of pH and is not very sensitive to the length of tubing along which it is measured.
Simplified Oil-Production Model With Viscous Flow, Gravity Drainage, Skin, and Instantaneous Oil/Steam Ratio for Mature Steamfloods
Authors: Closmann Philip J.
Published: December 2007

A simplified model estimates oil production rates for mature steamfloods. The mechanisms included are gravity drainage and viscous flow of the oil induced by flowing steam. Three examples of vertical wells are presented. The oil/steam ratio is also illustrated, as well as the pressure drop in the steam phase. One application of the model to horizontal wells producing by gravity drainage is also presented.
Pressure-While-Drilling Data Improve Reservoir Drilling Performance
Authors: Ward Chris , Andreassen Espen
Published: December 2007

A new downhole annular pressure-while-drilling (PWD) tool has been applied recently to assist in drilling the reservoir section on the Statfjord field, offshore Norway. For drilling success in these high-angle wells it is critical to maintain the mud weight and equivalent circulating density (ECD) within safe operating limits defined by the formation fluid, collapse, and fracture pressures. Operating outside these limits historically has led to expensive lost circulation, differential sticking, and packoff incidents. Monitoring the actual downhole pressure in real time with a PWD tool, rather than relying on inferred pressures from predictive models, has allowed the operator to stay within and to better define these operating limits. The operator used this improved hydraulics information to avoid pressure-related hole problems, to optimize drilling practices, to test hydraulics models, and to obtain a greater understanding of the formation pressure limits.
Innovative Technology for Tubular Connection To Eliminate Thread-Compound Grease
Authors: Tsuru Eiji , Maruyama Kazushi , Oka Masaharu , Higuchi Seijun
Published: December 2007

The doping of thread-TCG (TCG) poses an environmental pollution threat, but it is essential to the performance of tubular connections. This paper deals with an innovative tubular-connection coating without TCG, and describes the galling resistance and connection performance under field conditions. To develop the new coating technique without TCG, pin-on-disk-type tribological tests were conducted. For the connections with the new coating, performance was evaluated with power tongs and full-sized testers. As a result of the testing, the make-and-break (M&B) of the connection without any liquid lubricant was accomplished by means of the new coating. The connection can maintain the same performance as the conventional connection with TCG. This new connection coating can solve the problems induced by TCG and simplify the running works of casing and tubing pipes.
Optimized Reservoir Management With Mixed Linear Programming
Authors: Currie J. C. , Novotnak J. F. , Aasboee B. T. , Kennedy C. J.
Published: December 2007

Reservoir engineers face a large number of possible development plans for major offshore oil fields. Some of the factors affecting development include product-processing capacities, drilling-rig availability, extended use of existing platforms, enhanced-recovery options, and subsidence-avoidance requirements. Reservoir simulation is an accepted technique for estimating production from oil and gas fields. Each possible development scenario is simulated separately to obtain future oil- and gas-production estimates from wells included in the scenario. Simulation results are analyzed for each run, and the optimal plan is selected. Enumerating all the possible drilling schedules is a difficult task, and, even with clusters of advanced scientific workstations, the computational requirements of simulation can be overwhelming.

This paper describes the application of linear mixed integer programming (MIP) to the combinatorial problem of generating the optimal redevelopment scenario for the Ekofisk field in the Norwegian sector of the North Sea. The MIP model determines the optimal redevelopment program and drilling schedule while maintaining operationally feasible product-processing requirements, drilling-rig use, and well/platform relationships. Optimality is based on the net present value (NPV) of the estimated production forecasts for the wells selected. Total recovered reserves is an alternative optimization criterion. Reservoir simulations generated the estimated production forecasts used in iterative runs of the optimized model. We discuss success of the approach and extensions.
Determining Residual Oil With The Nuclear Magnetism Log
Authors: Robinson J.D. , Loren J.D. , Vajnar E.A. , Hartman D.E.
Published: December 2007

Given a reservoir with an immobile oil saturation, a mobile water phase, and proper open-hole conditions, the nuclear magnetism logging tool can be used to determine the amount of residual oil and the vertical distribution of the residual oil near the wellbore. Unique to the method is that the interpreter can control the precision of the results obtained.

Introduction

Methods of determining oil in place using underground surveys are indirect; that is, secondary properties are measured and the desired primary characteristics are derived from empirical relations with these secondary properties. Most of these methods must account properties. Most of these methods must account for contributions that both rock and fluid make to the measured signal. The nuclear magnetism log (NML) is unique because its signal is from the pore fluid alone. In this report we present a technique that takes advantage of this response characteristic of the NML and enables us to estimate immobile oil after water displacement.The NML tool detects protons in molecules of whatever liquids are contained in a formation immediately adjacent to the wellbore. In Ref. 1 it has been shown that if both water and oil are present the total response is equal to a contribution present the total response is equal to a contribution from the oil phase (which is relatively uninfluenced by confinement in rock pores), plus a contribution from the water phase (which is highly influenced by the pore size and matrix properties of the rock).The tool that was used to obtain the field results presented here caused magnetic fields to be applied presented here caused magnetic fields to be applied to the formation as shown in Fig. 1a. During time Tp the induced magnetization grows toward an equilibrium value proportional to the field strength Hp according to(1)

Upon removal of the high field, the induced magnetization decays toward a lower equilibrium value proportional to the low-field strength, HL, according to(2)

The growth and decay of the induced magnetization described by Eqs. 1 and 2 are illustrated in Fig. 1b.After the low field is removed the protons respond to the presence of the earth's magnetic field and proton free-precession takes place in the process of proton free-precession takes place in the process of achieving equilibrium. An exponentially decaying voltage with decay constant T2 and amplitude proportional to the magnetization is induced in the proportional to the magnetization is induced in the coil of the tool and is expressible as(3)

Fig. 1b illustrates the induced voltage as it decays during the free-precession period. The second term of Eqs. 1 through 3 is a sum because the T1 of the response from the water will depend upon the size of the pore in which it is contained.

JPT

P. 226
Common Business Objects: Demonstrating Interoperability in the Oil and Gas Industry
Authors: McLellan S. G. , Abusalbi Najib , Brown Johnny , Quinlivan W. F.
Published: December 2007

The PetroTechnical Open Software Corp. (POSC) was organized in 1990 to define technical methods to make it easier to design interoperable data solutions for oil and gas companies.1–7 When POSC rolls out seed implementations, oilfield service members must validate them, correct any errors or ambiguities, and champion these corrections into the original specifications before full integration into POSC-compliant, commercial products.8–10 Organizations like POSC are assuming a new role of "promoting formation of projects where E&P companies and vendors jointly test their pieces of the migration puzzle on small subsets of the whole problem."11,R12 We describe three such joint projects. While confirming the value of such open cross-company cooperation, these cases also help to redefine interoperability in terms of business objects that will be common across oilfield companies, their applications, access software, data, or data stores.13,R14
Cocurrent and Countercurrent Imbibition in a Water-Wet Matrix Block
Authors: Pooladi-Darvish Mehran , Firoozabadi Abbas
Published: December 2007

Imbibition in water-wet matrix blocks of fractured porous media is commonly considered to be countercurrent. The modeling studies of this paper indicate that when a matrix block is partially covered by water, oil recovery is dominated by cocurrent imbibition, not countercurrent. It is also found that the time for a specified recovery by the former can be much smaller than that by countercurrent imbibition. Consequently, use of the imbibition data by immersing a single block in water and its scale-up may provide pessimistic recovery information. Moreover, it is shown that the application of the diffusion equation for modeling of oil recovery by cocurrent imbibition leads to a large error. Through a detailed study of the governing equations and boundary conditions, significant insight is provided into the mathematical and physical differences between co- and countercurrent imbibition.
Sequential Semi-Implicit Algorithm for Computing Discontinuous Flows in Porous Media
Authors: Vegas-Landeau M. A. , Propp Rick , Patzek T. W. , Colella Phillip
Published: December 2007

This paper presents a novel numerical algorithm for computing incompressible, discontinuous, two-phase flows in two-dimensional (2D), inhomogeneous, and isotropic porous media. The algorithm uses Bell et al.'s hybrid sequential semi-implicit approach1 for both accuracy and efficiency of the calculations. The explicit part uses a high-order Godunov2 scheme with a modified Van Leer geometrical slope limiter, similar to those used in shock dynamics. The implicit part is a two-step solver. The first step is a Crank-Nicolson saturation solver, and the second is a Poisson solver for the phase pressure. Both use fast, multilevel, multigrid solvers with the number of operations of the order of O[N log(N)], where N = number of gridpoints. Two numerically stiff reservoir engineering problems are presented to demonstrate the low numerical dispersion and second-order accuracy of our method.