bluuebunny/crossref_metadata_2025 huggingface dataset:
Mathematical Properties of Three-Phase Flow Equations
Authors: Guzman Rafael E. , Fayers F. John
Published: December 2007

The equations for nondiffusive three-phase flow with gravity are examined according to the relative permeability model used. Three different classes of equations are distinguished (1) hyperbolic with a single umbilic point, (2) hyperbolic with multiple umbilic points, and (3) mixed hyperbolic and elliptic. The new equations with multiple isolated umbilic points are obtained when using Corey relative permeabilities that allow inflection points (i.e., extended Corey models). An example in which gravity and extended Corey relative permeabilities appear to give strictly hyperbolic equations is also included. The influences of viscosity, gravity, and relative permeabilities on the location of these umbilic points are shown. The relationship between the umbilic point(s) and the elliptic regions is discussed. The effect of gravity on the size of the elliptic regions is analyzed. It is shown that the size of the elliptic regions can be significantly increased or decreased by changing the gravity to viscous ratio, but without following an obvious systematic pattern.
Simulation of Gravity Override in Foam Processes in Porous Media
Authors: Shi J.-X. , Rossen W. R.
Published: December 2007

Foam can improve sweep efficiency in gas-injection improved-oil-recovery processes. The success of continuous-injection foam processes in overcoming gravity override in homogeneous, anisotropic (kx ≠ kz), radial or rectangular reservoirs depends on a single dimensionless number first proposed by Stone and Jenkins for gas flooding without foam. Their model fits foam-simulation results remarkably well over a wide range in reservoir properties and geometry, flow rates, foam quality and strength, initial reservoir pressure, and model for the mechanisms of foam collapse. This approach leads to optimal design strategies for such processes. Limitations on injection-well pressure may make it impossible, however, for a continuous-injection foam process to suppress gravity override in some cases. The possibility of gravity override within the foam bank should be considered in evaluating foam propagation in field trials of foam processes.
Results of Using Formaldehyde in a Large North Slope Water Treatment System
Authors: McLelland W.G.
Published: December 2007

In an effort to alleviate severe injection well plugging at Prudhoe Bay, formaldehyde treatment of the Flow Station 2 produced water was initiated in early 1991 and continued through mid 1995 when the program was terminated. Formaldehyde was selected because of its biocidal properties and cost. The results of these treatments are discussed in terms of the overall effect of formaldehyde on the system. Other events that impacted produced water quality at the facility, and subsequently the results of the formaldehyde program, are also discussed.

Introduction

The Prudhoe Bay Field is jointly operated by Arco Alaska, Inc. and British Petroleum Exploration on behalf of the Prudhoe Bay co-owners. ARCO is operator of the EOA (eastern operating area) which consists of three oil, water, and gas separation facilities termed Flow Stations. The Flow Station 2 facility handles fluids and gas produced from the eastern most area of the field and production is waterflood dominated.

The source water for the Prudhoe Bay waterflood was initially seawater. However, as breakthrough occurred, produced water was re injected as part of the flood with a corresponding decrease in seawater.

In 1990, additional produced water handling equipment was added at Flow Station 2 in order to treat the expected 700 KBWD peak water production anticipated before the end of flood life. The new treating equipment is set up to allow the separated produced water from the slug catchers and chem-electric treaters to gravity feed into an 18 Kbbl cone bottom tank (81 tank) with sand jet capabilities. The produced water stream exiting this tank is then split and the fluid enters two 12 Kbbl tanks (82 & 83 tanks) designed for free oil removal by gravity segregation. From these tanks, the fluid stream is recombined and fed into a header. The header feeds the produced water stream into four rotor type dispersed gas flotation cells (GFCs). The water from the flotation cells is directed through a series of pumps and ultimately to the produced water distribution piping for re-injection into the formation as part of the waterflood.

Concurrent with the startup of the new treating facilities, there appeared a sharp increase in the volume and severity of a black amorphous solid material in the produced water system and reports of "black water" caused by iron sulfide. This material collected in the facility and in the injection wellbores creating numerous problems with severe oil carryover, level controllers, pump strainers and seals, and routine well work. The buildup in the wellbores became so severe that it was virtually impossible to run any type of tool into an injection well without first cleaning out the wellbore.
A Semi-Analytic Method for Thermal Coupling of Reservoir and Overburden
Authors: Weinstein H.G.
Published: December 2007

A semianalytic method of handling the energy balance solution in the overburden has been developed. The method results in a single overburden energy coupling equation applicable at the reservoir - overburden boundary. This feature facilitates simultaneous solution of the pressure and energy equations in the reservoir. Test problems show the semianalytic method to compare favorably with the fully finite-difference technique. Both reservoir - overburden boundary temperature and the important factor of beat transfer into the overburden are accurately predicted by the method. predicted by the method. The semianalytic procedure may have considerable usefulness in the solution of reservoir problems. The method can definitely be applied in thermal simulation programs. Other anticipated applications are to an aquifer underlying a reservoir, an overlying gas cap, or to increasing definition in the vicinity of a wellbore. In each of these applications, the semianalytic procedure is expected to be considerably faster than the finite - difference solution.

Introduction

In thermal reservoir simulation programs, the material balances are solved over the reservoir; the energy balance is solved over the underburden-reservoir-overburden system. Hence, to avoid excess storage and computation time requirements, the material and energy balances are generally not solved simultaneously. In many cases it would be desirable to solve simultaneously the material balances (or equivalently, the pressure equation obtained by combining the material balances to eliminate saturation) and the energy balance. Problems with solution convergence and the treatment of mass transfer terms could be avoided in this way. This paper describes a semianalytic method of handling the energy balance solution in the overburden (and underburden). This solution results in a single overburden energy coupling equation that can be solved easily in conjunction with the reservoir pressure and energy equations. pressure and energy equations. The paper presents the mathematical development of the method and shows results for several test problems. The problems are similar to those encountered in thermal recovery processes. They compare the semianalytic method with the fully finite-difference procedure and, in one of the problems, with a completely analytic procedure and, in one of the problems, with a completely analytic solution.
A Scaleable, Database Architecture for Storage of PVT Data
Authors: Jefferson L. L. , Nighswander J. A. , Chang-Yen D. A.
Published: December 2007

Convenient access to fluid-property data in electronic form is currently not available in many petroleum organizations. Ready access to this information could result in significant cost savings by reducing the need for repeated studies and reducing the scope of new studies by analogous fluid evaluation. This work presents an overview of the development of a new scaleable database application to address these issues. In addition, we discuss design and development issues related to database scaleability. The application, PVT ReCORD, is currently undergoing beta testing by a major commercial laboratory that is creating an on-line fluid-property repository and automating pressure/volume/temperature (PVT) report generation with this tool.
An Interactive 3D Fracture-Modeling Environment
Authors: Swaby P. A. , Rawnsley K. D.
Published: December 2007

We describe an original three-dimensional (3D) fracture-modeling environment that is designed to allow users to construct interactively near-well fracture models suitable for use as input to fluid-flow simulators. Data input consists of a surface model of the seismic-scale structure, well-fracture data, and user-defined parameters. Sedimentary discontinuities and faults can be extrapolated from the wells in three dimensions (3D). Within this near-well model, tension fractures can be generated by use of a genetic process that aims to reproduce the initiation, growth, and interaction of fractures to create realistic fracture systems. Graphs are available for calibrating the fractures to assumed statistical distributions.
A Statistical Study of Rheological Models for Drilling Fluids
Authors: Weir Iain S. , Bailey William J.
Published: December 2007

In order to determine laminar friction losses of non-Newtonian drilling fluids it is standard practice to utilise a simple rheological model with parameter estimation via explicit solution of the required number of simultaneous equations. This limits the choice of available models and, together with the fitting procedure, frequently results in poor fits. Numerous alternative models have been proposed, but their worth has never been clearly demonstrated. Here we consider the rheological models to form the deterministic part of a stochastic model hence acknowledging that observed data arise from randomness due to the system. Parameter estimates are obtained by nonlinear least squares using data readings from eight standard Fann viscometer settings. Results are presented for 20 rheological models on 414 Fann viscometer data sets that encompass a variety of different drilling fluids. The goodness of fit of the models is assessed by comparing boxplots of the resulting residual mean square values. Several of the alternative models are shown to be consistently capable of excellent shear stress prediction over all of the shear rate range expected during drilling operations. The use of statistical methodology allows us to go beyond mere data relationship estimation: it permits the calculation of confidence intervals and tests of significance of functions of the model parameters, for example equivalent circulating density. The validity of such calculations relies on the extent to which the behaviour of the nonlinear least squares estimates approximates the asymptotic properties of being unbiased, normally distributed and minimum variance estimators. The estimation behaviour of the ‘best’ fitting models is analysed and a reparameterised form of the Sisko model is identified as having reasonable behaviour. Thus, despite the small data size, when using this model form the subsequent estimates, confidence intervals and tests of significance of functions of the model parameters can be confidently reported.
The Phase and Volumetric Behavior of Natural Gases at Low Temperatures and High Pressures
Authors: Davis P.C. , Bertuzzi A.F. , Gore T.L. , Kurata F.
Published: December 2007

The phase and volumetric properties of 10 very volatile mixtures are presented for temperatures from - 200 degrees F to above the critical points. These mixtures consisted of natural gases and of mixtures of natural gases with methane and nitrogen. Existing correlations of compressibility factors have been extended to apply to these mixtures. Existing correlations of critical pressures and temperatures do not apply to these mixtures. Methods have been developed for estimating critical temperatures of these mixtures to +/- 4 degrees F and critical pressures to +/- 5 per cent. These methods apply to other volatile and very volatile mixtures.

The results of this work are particularly applicable to the separation of nitrogen from hydrocarbons by low-temperature distillation.

Introduction

Knowledge of the low-temperature phase and volumetric properties of natural gases and of other mixtures of the light hydrocarbons is becoming increasingly important as interest in low-temperature separation processes increases. Low-temperature distillation has been used to separate ethane and ethylene from natural gas and from refinery gases for petrochemical uses. Removal of nitrogen from natural gas by low-temperature distillation has been proposed as a means of increasing the capacity of existing gas transmission lines and of improving the marketability of the gas.

Further application of low-temperature separation processes has been retarded by lack of data on the phase and volumetric behavior of mixtures at low temperatures and at high pressures. This paper presents the results of determination of the phase and volumetric properties of 10 very volatile mixtures at temperatures from - 200 degrees F to above the critical point. These mixtures consisted of natural gases with methane and nitrogen. Generalized methods are presented for estimating the critical temperatures, critical pressures, and the densities of such mixtures.
Numerical Laplace Transformation of Sampled Data for Well-Test Analysis
Authors: Onur Mustafa , Reynolds A. C.
Published: December 2007

In recent years, the numerical Laplace transformation of sampled data has proven to be useful for well-test analysis applications. However, the success of this approach is highly dependent on the algorithms used to transform sampled data into Laplace space and to perform the numerical inversion. We present new algorithms to accurately transform sampled data into Laplace space and to minimize "tail effects" resulting from the extrapolation of tabulated data. The algorithms presented can be applied to generate accurate pressure-derivative data in the time domain. We show that performing curve-fitting (without inversion) in Laplace space with the algorithms presented is computationally more efficient than performing it in the time domain. Applications of the algorithms to convolution, deconvolution, and parameter estimation in Laplace space are also presented. Both synthetic and field examples are considered to illustrate the applicability of the proposed algorithms.
Pore Network Model for Foam Formation and Propagation in Porous Media
Authors: Kharabaf Hooshang , Yortsos Yanis C.
Published: December 2007

A simple pore-network model, based on a pores-and-throats representation, is developed to simulate the generation and mobilization of foams in porous media. Contrary to previous works, the model simulates a dynamic invasion process, in which gas invades a porous medium occupied by a surfactant solution. For the front to advance, the applied pressure gradient needs to be sufficiently high to displace a series of lamellae along a minimum capillary resistance path. We determine this path using a novel algorithm simulating invasion percolation with memory (IPM).1 We focus on the properties of the displacement, the onset of foam flow and mobilization, the foam texture and displacement efficiencies and the fractions of flowing and trapped lamellae, as a function of parameters, such as the snap-off probability. Comparison with experiments shows a generally good agreement, despite the simplicity of the model. The invasion by foam of low permeability layers during injection in a heterogeneous system is also demonstrated.
A Pilot Test of Polymer Flooding in an Elevated-Temperature Reservoir
Authors: Tielong Chen , Zhengyu Song , Fan Y. , Changzhong Hu , Ling Qiu , Jinxing Tang
Published: December 2007

We conducted a pilot test of polymer flooding in the Shuanghe reservoir located in the southeast Henan oil field, China. The target reservoir has a net thickness of 15.56 m (50 ft), an average permeability of 420 md, and a temperature of 75°C (167°F). The polymers used are two types of modified partially hydrolyzed Polyacrylamides, named S525 and S625, which have molecular weights of 16,700,000 and 19,670,000 daltons, respectively. The objective of this pilot test is to investigate the feasibility of polymer flooding for improving oil recovery in an elevated-temperature reservoir.

The polymer flooding started in February 1994. Through December 1995, a total of 246 tons (about 0.5 × 106 lbm) of dry polymer had been used with an injection concentration of 900 to 1,100 ppm. The pore volume (PV) injected reached 0.2164. As a result, oil production increased by 22,000 tons (184,000 bbl) and water production decreased by 153,000 tons (962,000 bbl), which accounts for the incremental oil recovery of 3.8% and water-cut reduction of 5.6% in the test block. We estimate that, by the end of this project, the ultimate increase in oil production will exceed 63,000 tons (528,000 bbl) with the enhanced oil recovery going up to 9.8%. The yield is 0.2 tons more oil produced per kilogram of polymer injected or 0.7 barrel of oil produced per pound of polymer.

We attribute the success of the pilot test to the techniques used during the implementation of the flooding, including prevention of polymer-thermal degradation, good reservoir description, and the profile modification carried out before and after the polymer injection. This pilot test illustrates a case where polymers with extra-high molecular weight are successfully injected in an elevated-temperature reservoir to control the mobility ratio and modify the permeability profile.
A New Approach to Forecasting Miscible Water Alternating Gas Performance at the Field Scale
Authors: Giordano R. M. , Redman R. S. , Bratvedt Frode
Published: December 2007

Full-field enhanced oil recovery (EOR) performance predictions are generally obtained from scale-up tools, because three-dimensional (3D) finite-difference simulations would be too CPU-inten- sive. Existing scale-up techniques require the user to define pattern elements and then to derive performance curves to apply to each injector-producer pair in the elements. Accurate assignment of these elements is difficult because the actual shape and size of the swept volumes are sensitive to reservoir faulting, well-rate changes, and regional flux. In reality, the actual sweep region is not an input parameter, but should be determined by the regional pressure field, which changes as well rates vary and new wells are drilled. Thus, a major source of error in using existing scale-up tools is trying to define representative pattern elements. In the current paper, we describe a scale-up technique in which the user does not have to define pattern elements or injector-producer pairs. In the new technique, the pressure field is computed at each timestep and then a front-tracking algorithm propagates water and miscible injectant throughout the reservoir. The miscible-gas process is modeled by means of an analogy between oil mobilization and adsorption/ desorption of tracers. The parameters for the model are obtained by fine-scale, two-dimensional (2D), compositional, finite-difference simulations in a vertical cross section. In the new approach, the injected solvent is divided into an effective and an ineffective portion. This approach reduces a 3D problem to a 2D, areal one in which the declining displacement efficiency of the solvent, which is caused by vertical effects, is captured by decreasing the injected concentration of effective solvent with time. In this paper, we show how the new scale-up tool has been used to model the miscible water-alternating-gas (MWAG) process in the Eastern Peripheral Wedge zone (EPWZ) of the Prudhoe Bay field. We show a comparison between field response and model predictions.
Advanced Tools for Advanced Wells: Rotary Closed-Loop Drilling System-Results of Prototype Field Testing
Authors: Poli Sandro , Donati Franco , Oppelt Joachim , Ragnitz Detlef
Published: December 2007

In the next few years, a revolutionary well-steering system will arrive to face the "advanced wells" challenge. After an extensive period of field testing, the "rotary closed-loop system" (RCLS) seems very close to having the capability of operating in any extended-reach, deep horizontal, or complex multilateral well and in a high-pressure/high-temperature (HPHT) environment. Additionally, mainly because of the elimination of a sliding operation, conventional directional wells will, in many cases, also greatly benefit. The RCLS was designed to control automatically well geometry during directional drilling, even while rotating the drill-string. Hydraulically powered, electronically controlled, expandable ribs, which generate a radial steering contact force to the borehole wall, adjust the wellpath. All parts, except a short steering sleeve, work continuously in rotation. The RCLS may be operated with or without a downhole motor. Several subsystems, e.g., the hydraulic components, most electronic modules, and the bottom-to-surface communication, were field tested during 1994 and 1995. The first field trial of the complete unit, drilling a total of 1067 m, was conducted in late 1995 at Montrose, Scotland. The field test program was continued in early 1996 to compare RCLS drilling and directional performance with the introduction of broadened operating parameters. During this prototype testing period, the efficacy of all major functions was fully verified.
Innovative ESP Completions for Liverpool Bay Development
Authors: Stewart D. R. , Holland Brian
Published: December 2007

This paper presents a review of the electrical-submersible-pump (ESP) completions installed in the Douglas field in Liverpool Bay-A number of innovations were introduced into the completion design successfully. These are discussed, along with the completion procedures and the excellent operational performance that was achieved during initial completions. ESP-runlife performance and the steps taken to maximize runlives are also discussed.
Selecting the Proper Rotary Rock Bit
Authors: Estes Jack C.
Published: December 2007

Introduction

On Aug. 10, 1909, Howard R. Hughes patented the first rotary rock bit, which he called a "boring drill." The drill resembled two pipe reamers set on journal bearings attached to a drillpipe sub. This invention enabled rock formations to be drilled and was the starting point for 62 years of rock-bit development. This development history is traced in Fig. 1. It is not our purpose here to discuss these changes, nor to detail the basic designs of rock bits. The major bit manufacturers provide, for the asking, very good manuals on this subject. It is our purpose to provide the engineer who plans casing and drilling programs with the plans casing and drilling programs with the information he needs to take advantage of the most modern bit technology. Casing programs that force the use of obsolete bit types, and drilling programs that do not run the new bits properly are programs that do not run the new bits properly are more costly than they need be. Optimization of drilling is coming into its own after 10 years of intensive development. Often, however, the optimization procedures are handicapped by preset casing programs that force the use of off-size or obsolete bits. How good is modern bit technology? If you are drilling a "standard" hole size, the answer is "great." We are drilling footages and hours on single bits that would have been unbelievable just 2 years ago. Many of the new design features, which were experimental in the early 1960's, have been made generally available in the last 4 years. As shown in Fig. 1, it is estimated that improvements in rock bit development have been 30 percent greater in the last 4 years than in the 50 previous years. In fact, some optimum drilling programs planned just last year for ultradeep wells have become obsolete before the wells have been completed because of the introduction of new types of bits that were not generally available when the wells were originally planned. planned. Roller-Rock-Bit Classification

Complete rock-bit nomenclature can be found in most bit catalogs and, therefore, will not be introduced here. However, several terms should be described for the following discussion. Rock bits are usually classified according to tooth material and height, cone offset, and journal angle. The teeth may be hard-faced, case-hardened, or inserts of tungsten carbide. The cone offset, sometimes called "skew," is a measure of how far the center line of a cone misses the center of the bit. Journal angle is the angle the center line of the bearing journal makes with the bottom of the hole. A rock bit may be built with any one of four different types of bearing assemblies: nonsealed roller, sealed roller, sealed journal, and "super" journal, with the price increasing in the order listed. A rock-bit classification guide based on these features for the four major bit manufacturers is given in Table 1. Bits on the same fine in the chart are designed to withstand roughly the same operating conditions.

JPT

P. 1359
Differences Between Methane and Condensate Kicks—A Simulation Study
Authors: Szczepanski Richard , Yerlett T. K. , Brown N. P. , Hamilton T. A. P.
Published: December 2007

An increasing number of the new developments on the U.K. continental shelf are condensate fields. The properties of condensates are different from those of gases or oils and, consequently, the onset of a kick in a condensate field may give rise to somewhat different surface indications and well-control problems than in the case of a gas kick that is conventionally assumed to be composed of methane.

This paper investigates the differences and similarities between gas kicks and condensate kicks both in water- and oil-based drilling fluids. Information on a wide range of condensate reservoir fluids has been gathered, and four representative fluids have been selected for comparison with methane. The behavior of a kick in a wellbore has been studied using two complementary approaches. First, the volume of a kick as it expands up the wellbore has been calculated by considering the effect of pressure and temperature changes. Second, a simplified dynamic model of a kicking well has been used to simulate the kick-detection and kick-kill phases of well control in a typical deep-well configuration. Although condensates are actually complex multicomponent mixtures, it seems possible to model condensate kicks reasonably well with a simple three-component model that is based on the gas/oil ratio (GOR).

The principal conclusion for safety is that failure to detect a condensate influx on entry to a well will make control of the kick when it reaches the surface more difficult. However, for kicks of the same size, a condensate kick will generally result in surface and shoe pressures less than those for a methane kick. Condensate kicks also should not be more difficult to detect.
Field Experience With Multilaterals in the Idd El Shargi North Dome Field, Qatar
Authors: Scofield J. R. , Laney Bill , Woodard Phil
Published: December 2007

This paper describes how one operator used the latest multilateral drilling technology to improve the profitability of the Idd El Shargi North Dome (ISND) field, offshore Qatar (Fig. 1). Dual openhole laterals have been employed to simultaneously exploit the Shuaiba A and B oil reservoirs. In each well drilled to date, the secondary wellbore has been cased off at the lateral junction following drilling of the fullbore lateral section. A mechanical junction has been used to ensure long-term mechanical integrity and re-entry capability following completion. To date, this technology has been used on five wells in the ISND field (IS-74, IS-75, IS-76, IS-77, and IS-80). Approximately 10 additional complex-drainage-architecture wells are planned in 1997 to further develop this field.
Technology Aids Risk Reduction and Transforms Resources Into Reserves
Authors: Caldwell R. H. , Heather D. I.
Published: December 2007

Changes in technology can alter status-quo thinking about risk and reward and proved reserves drastically. These changes can be subtle or far reaching and can result in a whole new language to describe their impact; the emergence of "paradigm shift" is an example. Faced with these changes, the decision maker must determine how to evaluate their impact quantitatively.

Intuitively, we think of reserves as relatively static quantities, although reserves do fluctuate with changes in price and operating cost (affecting the economic limit) and also with the magnitude of capital costs. Proved undeveloped reserves exist when the required capital investment generates an acceptable return. These reserves become resources when that return requirement is not met. The ability to reduce capital costs and/or risk opens up lower-quality resources to the prospect of economic recovery and the potential to become reserves. Study of the size distribution of such resources shows that small pools can contain successively greater quantities of reserves than pools in larger-size classes. As a result of new technology, development of such pools in a controlled cost and risk environment can represent as great a prize as a large-pool discovery. The ability to "change the rules" because of technology advances opens a vast opportunity for energy self-sufficiency that has ramifications on a national scale.
A Field Test of Surfactant Flooding, Loudon, Illinois
Authors: Pursley S.A. , Healy R.N. , Sandvik E.I.
Published: December 2007

Illustrated here are procedures that were used to interpret a pilot test of tertiary recovery employing an aqueous solution of petroleum sulfonates. Information derived from a comprehensive tracer program indicated that the effectiveness of the recovery process was reduced by an excessive mixing of surfactant solution with high-salinity formation brine.

Introduction

One of the more difficult phases in the development of any new oil recovery process is the design, implementation, and interpretation of pilot tests. Such tests are usually quite expensive, yet represent only one of the many possible sets of operating conditions. Consequently, the operator should take every possible precaution to choose an optimum set of conditions precaution to choose an optimum set of conditions and to design a pilot that provides maximum opportunities for interpretation. Previous laboratory work had pointed to the effectiveness of surfactants of the type described in the patent literature for use in improved secondary or patent literature for use in improved secondary or tertiary recovery applications. Laboratory studies of these materials had ranged from detailed chemical investigations to floods in reservoir cores, as well as linear and areal models cut from outcrop rock samples. Interspersed with the laboratory studies were field tests that evaluated the injectivity of surfactant systems and pattern oil recovery. This paper describes a surfactant pilot test conducted in a watered-out portion of the Loudon field, Illinois, during the period 1969-1971. In addition to having the usual goal of determining the level of operability in this field, the test was specifically designed to determine (1) the extent of surfactant adsorption-fractionation and the resulting effect on oil recovery, (2) the degree of mobility control achieved and its effect on sweep efficiency and oil recovery, and (3) any additional problems not uncovered in the relatively simple laboratory systems.
Work-Flow Automation Enhances Job Performance and Improves Job-Execution Data
Authors: Schmitzer J. L. , Randall J. D.
Published: December 2007

We designed and implemented a work-flow automation system to automate the flow of operational data throughout a servicing operation. Work-flow automation enables well-service personnel who are rarely network-connected to access information systems containing updated job requirements and well data. As the service personnel perform their work, data from the job are stored on a personal computer by use of store-and-forward architecture. Once the computer connects to the wide area network (WAN), job data are forwarded to the service-center operations systems. Copies of these data also can be forwarded to the customer to demonstrate enhanced value or to track cost. In this pilot implementation, we decreased the number of paper forms substantially, increased the quality of data collection, distributed updates to the system to the field easily, and relayed key data to the customer quickly. This paper documents the pilot implementation of this system and the lessons learned from its implementation.
The Permeability of a Uniformly Vuggy Porous Medium
Authors: Neale Graham H. , Nader Walter K.
Published: December 2007

Using the creeping Navier Stokes equation within a spherical cavity and the Darcy equation in the surrounding homogeneous and isotropic porous medium, the flow field in the entire system is evaluated.

Introduction

The objective of this study is the derivation of an engineering formula that shows the interdependence of matrix permeability, km, vug porosity, ɸv, and system permeability, ks , of a uniformly vuggy porous medium.6 In the first section, with the above goal in mind and to satisfy more general interests, we shall study and predict the flow field within a single cavity bounded by a sphere, of radius R, and in the surrounding homogeneous and isotropic porous medium. In the second section, we shall suggest as a generalizing model of a uniformly vuggy, homogeneous and isotropic porous medium a regular cubic array of monosized spherical cavities. Applying the formula for the pressure field near a single spherical cavity, we shall then develop the sought engineering formula.
Bending Torque and Strain Energy in Reeling Coiled Tubing
Authors: Yang Yong S.
Published: December 2007

In this paper, formulas for determining torque and strain energy in reeling coiled tubing are derived. The general formula for calculating torque is simplified by using fully plastic deformation replacing elastoplastic deformation. The simplified torque is within 0.25% relative error as compared to the torque formula obtained by using elastoplastic assumption. Most of the strain energy in reeling coiled tubing is dissipated (converted into heat). Only a small part of the total strain energy is recovered. The recovered energy is the elastic energy that is stored during reeling. The stored elastic energy typically accounts for 5% to 15% of the total strain energy in reeling, depending upon tubing and spool sizes as well as tubing material mechanical properties.
Finding the Most Profitable Slug Size
Authors: Jones Stanley C.
Published: December 2007

Several current sophisticated oil recovery projects involve injection of a slug consisting of a micellar solution, and carbon dioxide or a hydrocarbon solvent. Slug costs combined with low oil saturation may result in marginal economics; thus, the economic success or failure of a miscible project may hinge on choosing the proper slug size. A simple technique will be described here for estimating the "optimum" slug size. Required data include oil price, average oil saturation, per-barrel slug cost, and a slug-size vs oil-recovery curve. The last item is most desirable obtained from pilot floods, but can often be estimated from laboratory data, provided that these results are corrected to allow for heterogeneities of the reservoir in which the flood is to be attempted. Failure to correct for heterogeneities will result in an optimistic prediction of production performance. performance. Profit from a flood is derived from the value of the oil recovered less the cost of slug, and drive fluids, capital expenditures, and operating expenses.

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

Oil recovery hence profit, is a function of, among other things, slug size. Assuming that the per-barrel slug cost is independent of slug size, the maximum profit for given reservoir conditions, oil price, profit for given reservoir conditions, oil price, chemical costs, etc., can be found by setting the partial derivative of a rearrangement of Eq. 2 with respect to slug size equal to zero:

............(2)

Maximum profit occurs when:

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

that is profit is maximum when the slope of the oil-recovery vs slug-size curve is equal to the right-hand side of Eq. 3. Fig. 1 shows four recovery curves. The uppermost curve shows laboratory data for micellar solution floods in which various slug sizes were used. Polymer solutions were used to propagate the slugs through 4-ft.-long-, 3-in.-diameter Berea sandstone cores. The three other curves were computed from these data by assuming that for each of them there were two equal-volume, equal-porosity layers, identical in all respects except for absolute permeability. Oil recovery is reduced with increasing permeability contrast, partly because slug is not equally accepted by the two layers, and partly because the tighter layer is not completely swept before the economic limit is reached. Other recovery curves could be generated, simulating more layers, pattern geometries other than linear, or other desired degrees of complication. Only simple cases are shown here, however, to illustrate the technique of determining optimum slug size. For purposes of illustration, let us assume that the cost of the injected micellar slug, is $5.00/bbl, the average preflood oil saturation is 0.35 and the price received for oil after royalties is $3.00/bbl. For this set of conditions, Cs / (SoPo) is 4.76. Lines of this slope are shifted up or down until they become tangent to the curves of Fig. 1. The point of tangency for each case represents the most profitable slug size.

P. 993
Use of Injection - Falloff Tests To Evaluate Storage Reservoirs
Authors: Mistrot G.A. , Dempsey J.R.
Published: December 2007

Introduction

Probably the single most important piece of reservoir Probably the single most important piece of reservoir data required in the conversion of a depleted gas field to gas storage service is effective rock permeability distribution, and this information is usually not available in sufficient detail during the primary depletion of the field. Wells are drilled on relatively wide spacing; and core or buildup data, even where available, provide insufficient points of control for adequate provide insufficient points of control for adequate mapping. Matching history with a reservoir simulator can sometimes fill in the gaps, but it is not uncommon for areal history matches to be somewhat insensitive to relatively wide variations in over-all reservoir permeability and individual well descriptive parameters (such as damage, turbulence, and crossflow) at the producing rates at which the field was depleted. producing rates at which the field was depleted. As the field is being converted to storage mode, infill drilling provides the required additional points of control. Normally, good porosity limits can be obtained through logging programs, but permeability is another matter.

Drilling into pressure-depleted reservoirs with gas-or nitrogen-lightened mud is often ruled out from a cost standpoint, and deep invasion is commonplace when nonaerated muds are used. Additionally, costs in general and costs and problems resulting from lost circulation usually preclude extensive coring.

Completed wells more often than not have significant damage and insufficient pressure to flow out invaded and produce at rates and pressures that well permit an acceptable evaluation. In addition to filtrate invasion, it is not uncommon for some solids to drop out, completely blocking the sand face and requiring the well to be acidizing before it will even accept gas on injection. Acidizing - even a small job - is at best a necessary evil as it adds more liquids to an already invaded zone. Deep and severe damage can affect pressure transients for a substantial period of time. period of time. A testing method must be designed that can yield usable information even at low rates and in severely damaged environments.
Field Welding on Oilfield Tubular Goods
Authors: Biron J.N. , Frazier B.G.
Published: December 2007

Examination of several typical samples of field welding of scratcher and centralizer lugs revealed that the quality of welds was inconsistent and generally poor. Damage to the casing could usually be expected. The holding capacity of the welded lugs and of the equipment itself against the lugs was found to be of a very low order.

A non-technical summary of the effects of welding on oilfield tubular goods is presented. It is shown that the tubular goods steels require a stricter welding procedure for quality welds than steels in general industrial use. A study of this will give the busy supervisor a fair appreciation of the problem of joining metals by arc welding.

Having established the effects of welding, the control of these effects as they concern field application is considered. Welding at the rig site is classed into five categories, namely,welding scratcher and centralizer lugs,welding collars, floating equipment,welding casing hangers,orange peeling of conductor to surface pipe, and finally,welding of casing and tubing as piping.

The peculiarities of each category are discussed and recommendations made when applicable.

Introduction

The frequency of holes in casing set in wells gave rise to the suspicion that the failures were related to the field arc welding done on the casing. The welding of scratcher and centralizer stops or lugs on casing is a common practice. It was decided to determine the quality of field welding of these appurtenances to the casing and to evaluate its effect on the wall body. Several typical samples of field welding of scratcher and centralizer stops were examined and tested.

After determining the quality of the welding being done in the field, the next step was to investigate methods of improvement. A review of published literature and consultation with welding engineers provided welding and metallurgical information. Since current laboratory knowledge was not being put to use, translation of the laboratory knowledge into a simple explanation for rig operations was needed. A brief and non-technical discussion of welding on high carbon-alloys steels was prepared to foster a better understanding of the problem by those supervising field welding operations.
A Proven Method for the Control of Incompetent Sand Formations
Authors: Ritch H.B.
Published: December 2007

A sand control process has been developed and field proven in the Gulf Coast. The mechanics of the application involve the use of a gel oil (or gel acid or gel water) as a vehicle to carry sand into or against the formation which has, or is expected to, produce sand. This process is carried on beneath a squeeze tool in order to cope with pressures which might otherwise be unsafe. This process makes it possible to pack a formation without mud or water contamination. After the formation is satisfactorily packed, the packing sand is held in place by a screen liner or sand consolidation plastic. Work has been done to determine the most effective packing sands and gravel. Results of this work are analyzed and tabulated.

Introduction

Sand control problems in the Gulf Coast are as old as oil production in this region. Several sand control methods have been developed; however, there have always been a few wells which defied any sand control measure. It was on wells of this type that the work described in this paper was initially done.

Many variables must be considered when the problem of sand control arises. Virtually all sand control measures are dependent on the bridging of formation particles against some screening mechanism placed in the well. This forms a filter which limits the movement of other formation solids into the well bore.

Certain basic information is desirable when preparing a sand control program:formation sand grain analysis;variations in sand size in individual zones;formation or producing interval thickness:mechanical hookup of well;subsurface depth of producing zone;degree of cementation of formation;lithology;well fluids to be produced (viscosity);bottom hole temperature and bottom hole pressure;quantity of fluid production; andsand control measures previously used and their success.

Some of this well information is difficult to obtain in the Gulf Coast region, due to the difficulty of recovering cores from the poorly consolidated formation.
Using Improved Technology to Obtain Better Cement Jobs on Deep, Hot Liners
Authors: Tragesser Art , Parker P.N.
Published: December 2007

Critical to the success of a cement job are an accurate knowledge of downhole temperatures, adequate laboratory simulation of field conditions, proper regard for the effects of mud contamination of cement, and efficient proper regard for the effects of mud contamination of cement, and efficient mud displacement. All of these factors are discussed here, particularly in the context of a two-well testing project in Southwest Texas.

Introduction

The design of cementing slurries is always critical on deep wells; however, it is even more so on liner casings because of the performance requirements that exist almost simultaneously at both the top and the bottom of the liner. In cementing full strings of casing, the cement's initial performance is usually judged only in relation to the producing zones near the bottom of the casing. On liner casings, the cement must also set up and provide an adequate seal at the top of the liner, which may be several thousand feet back up the hole. Static formation temperatures at the top of the liner may be much lower than at the bottom. and may in fact be less than the circulating temperature for which the cement slurry was designed. This cement must be efficient in displacing the drilling mud from behind the entire liner, and must have reached the top of the liner sufficiently uncontaminated to set up, it must have adequate compressive strength to hold a pressure test. Mud-contaminated cement at the top of the liner is almost always a problem because of the relatively small volumes of cement required to fill the annulus, and there is a hesitancy to use much excess cement. The use of large volumes of cement behind the drillpipe can have disastrous results if the cement sets up before the drillpipe is removed from the well. In addition to the primary performance criteria discussed above, a deep-liner cementing slurry must also have adequate density to prevent the flow of formation fluids, particularly gas, into the wellbore. The slurry must also have satisfactory rheological properties to prevent formation breakdown while it is properties to prevent formation breakdown while it is being pumped into the annulus. Because many of these factors are ignored, the success ratio of liner cementing has been less than satisfactory. However, analyses indicate that many more successful jobs may be obtained if careful engineering is used to achieve the following:

1. Better analysis of well temperature conditions.

2. Closer laboratory simulation of actual well conditions to yield accurate results.

3. Greater compatibility between oil mud and cement.

4. More thorough mud displacement.

With the objective of improving primary cementing success, these concepts were tested on two wells drilled in areas of Southwest Texas where previous experience showed that conventional approaches were inadequate.