bluuebunny/crossref_metadata_2025 huggingface dataset:
Fluosilicate Solubilities Affect HF Acid Compositions
Authors: Gdanski R. D.
Published: December 2007

The purpose of this work was to determine the solubilities of sodium and potassium fluosilicate over a broad range of HCl concentrations, ionic strengths, and temperatures. These data were required for determining optimum or safe HCl/HF treating-fluid compositions for acidizing sandstone formations containing feldspars. Solubilities of sodium and potassium fluosilicate were determined over a temperature range of 150 to 300°F. Analysis of the solubility data indicated that the solids formed were not simply Na2SiF6 and K2SiF6. Regression analyses indicated that the sodium salt could best be described as NaHSiF6 · 0.52HCl (or Na0.48H1.52SiF60.52NaCl). Regression analyses indicated that the potassium salt could best be described as KHSiF6 · 0.41KCl (or K1.41H0.59SiF6· 0.41 HCl). The solubility data were then included in a HF-spending simulator to determine regions where possible precipitation of the fluosilicates could occur. Optimum HCl/HF concentrations were then determined for specific mineral and temperature conditions.
A New Technique for Evaluating Field Cement Mixing
Authors: Benge Glen
Published: December 2007

Cement service companies have developed spacer systems to address various flow regimes, developed a wide array of mixing equipment and have written computer simulation programs to address a wide range of well parameters. Most of the simulation programs evaluate hole geometry, wash uts, eccentered casing, and U-tube effects. While these designs, developments and job simulations are desirable and necessary, it is important to understand the limitations of the available field mixing equipment and the ability of that equipment to deliver a cement slurry at the specified density and rates required by these designs. This study investigates the ability of existing mixing equipment to deliver a cement slurry at a specified density and rate.

This paper takes data recorded on location and graphically presents it in a three dimension graph of rate, density and volume percentage. This differs from the data presentations available from the service companies. The graphs offered by the cement companies typically plot density, rate and pressure vs. job time. This is useful for determining the events during the job, but does not allow for analysis of the mixing characteristics of the cement unit.

This paper presents three dimension histograms from several cement jobs, attempts to evaluate the mixing errors on those jobs, and outlines the efforts taken to correct the problems. A comparison is made to two dimensional histograms evaluating only the density variations. Also presented are data on some jobs where the main objective appears to be the control of the mixing rate, rather than density control. The majority of the data evaluated in this study is from offshore installations. This allows for in-depth evaluation of both the cement unit and the cement delivery system. For consecutive jobs, the same piece of equipment is used, thus eliminating some additional variables in the evaluation.

The data reveals several trends in cement mixing. The types of mixing noted in this project are: (1) Mixing where the control of density and rate is very poor, (2) Rate controlled mixing where the mixing rate was the controlling factor, (3) Density driven mixing where concern over the slurry density took precedence over rate and (4) Density and rate control appear to be in concert.

From the data evaluated, this analysis method allows for better evaluation of cement mixing, and the quantification of mixing characteristics of various pieces of cement equipment. It will allow for a direct evaluation of the value of adding specific pieces of mixing equipment such as averaging tanks, batch tanks, recirculating mixers, etc. Properly used, the presented evaluation technique should allow the operator to optimize the total cement mixing system through the selection of the most consistent mixing unit.
Interactive Visual Identification of a Reservoir Boundary Integrating Seismic and Well-Test Data
Authors: Swaby P. A. , Beydoun W. B. , Guérillot D. R.
Published: December 2007

We describe an interactive system designed to allow users to identify a range of possible reservoir boundaries given a seismic subsurface image and well-test information. Traditionally, data from these two sources are considered separately. This system was developed to interpret both forms of information simultaneously. This is achieved by displaying the seismic image, allowing the user to characterize the seismic uncertainty resulting from the reservoir delineation (i.e., by selecting inner and outer reservoir boundary limits), choosing an intermediate reservoir boundary, running a fluid-flow simulation, and comparing the results with the well-test data. In addition, the system incorporates a multiwindowing interface and has been developed for use by noncomputer specialists.
An Object-Oriented Solution to an Interdisciplinary 3D Visualization Tool
Authors: Sinclair Craig , Little Todd , Rahi M. Ahsan
Published: December 2007

This paper describes the design and implementation of an interdisciplinary 3D visualization tool. An object-oriented approach was used to overcome deficiencies within third-party graphical tool kits and incompatible data formats. It also facilitated multidisciplinary visualization by providing a coherent framework for combining drawing technologies from the different disciplines. The tool kit was designed to be extensible and supportable because it was expected to continually evolve to meet new market requirements.
STORM: Integrated 3D Stochastic Reservoir Modeling Tool for Geologists and Reservoir Engineers
Authors: Bratvold R. B. , Holden Lars , Svanes Tarald , Tyler Kelly
Published: December 2007

The petroleum industry is focusing on improved reservoir characterization. Decisions concerning development and depletion of hydrocarbon reservoirs must be made while giving consideration to the uncertainties of the formation involved. This requires combining geological and engineering data to develop a detailed reservoir model.

Geostatistics and stochastic modeling techniques have emerged as promising approaches for integrating all relevant information and describing heterogeneous reservoirs. By use of stochastic techniques to generate a range of equiprobable reservoir descriptions, the uncertainty in the important reservoir parameters can be quantified. This quantification, together with the enhanced understanding of the reservoir characteristics given by stochastic reservoir modeling and visualization, provides an essential basis for making informed field-development decisions. This paper presents an integrated approach for stochastic reservoir evaluation. The presented approach has been implemented in the software system STORM.
Simplifying the Task of Grouping Fluid Components in Compositional Reservoir Simulation
Authors: Lomeland Frode , Harstad Olav
Published: December 2007

We present and test a new method for selection of pseudocomponents and averaging equation of state (EOS) parameters with excellent results. The new method is especially useful for compositional reservoir simulation with or without extended downstream process modeling.
Pore-Compressibility Study of Arabian Carbonate Reservoir Rocks
Authors: Harari Zaki , Wang Shu-Teh , Saner Salih
Published: December 2007

In the laboratory, we determined the pore-compressibility characteristics of some limestone samples obtained from a Saudi Arabian petroleum reservoir. The samples were saturated with water and subjected to confining pressure, pc, and pore pressure, pp, in a core holder, and the resulting reduction in PV was measured. We used differential pressure, pc–pp, ranging from 0 to 4,500 psi. Differential pressure was increased incrementally by reducing the internal (pore) pressure while maintaining a constant hydrostatic confining pressure on the rock samples.

We present the experimental data here in the form of relative porosity and hydrostatic pore-compressibility values as functions of differential pressure. We analyzed the test results after grouping the rock samples on the basis of their lithological description. Four groups of limestone samples consisting of grainstones, packstones, wackestones, and mudstones were studied. Also, Berea sandstone was tested for comparison with limestone. The results show linear negative correlations on a log-log scale between pore compressibility and differential pressure for all the tested samples. Consequently, we computed the pore compressibility vs. differential-pressure power-fit parameters (referred to here as parameters Ac and Bc). We found that parameters Ac and Bc are correlated with initial porosity for the tested samples and inter-related within the same lithologic group. Mathematical expressions for predicting pore compressibility and porosity as functions of differential pressure are given for the tested samples.
Rangely Weber Sand Unit CO2 Project Update
Authors: Masoner L. O. , Wackowski R. K.
Published: December 2007

The Rangely Weber Sand Unit miscible CO2 project was initiated in Oct. 1986 and results to date have been encouraging. The development plan of the project has evolved to meet challenges that have developed since startup. Operational changes have also been implemented to improve the economic performance of the unit.
Core Acquisition and Analysis for Optimization of the Prudhoe Bay Miscible-Gas Project
Authors: McGuire P. L. , Spence A. P. , Stalkup F. I. , Cooley M. W.
Published: December 2007

Core data from a sidetrack well 250 ft from an old injection well showed intervals of excellent miscible-gas sweep, with miscible-flood residual oil saturations (ROS's), Sorm, of ≈ 5% PV. Less-well-swept intervals had intermediate Sorm values. Numerous intervals had not been contacted by miscible injectant (MI). Chromatographic analyses of the Dean-Stark core extracts quantified miscible-gas alteration of the oil and was especially valuable in the interpretation of intermediate oil saturations. Compositional reservoir simulations showed that high-permeability thief zones and a number of thin shales controlled sweep efficiency near the cored well.
A Novel Recovery Mechanism for Polymer Flooding In Gravity-Dominated Viscous-Oil Reservoirs
Authors: Goodyear S. G. , Mead B. J. , Woods C. L.
Published: December 2007

Development of North Sea viscous-oil fields represents a new challenge to the industry. A number of these reservoirs comprise relatively clean homogeneous sands with high horizontal and vertical permeabilities. The oil viscosities are in the range of 5 to 200 cp and oil columns are typically < 200 ft thick and often partially underlain by water. Waterflooding is dominated by gravity in the interwell region, with water slumping to the bottom of the reservoir and coning up to producers. Development depends on the use of horizontal wells to reduce the coning.

The viscous oil and poor vertical sweep make these reservoirs possible targets for IOR with polymers. This study shows that polymer incremental recoveries can be high, well within the range of potential economic viability. The incremental recovery mechanism is not the usual improved Buckley-Leverett sweep efficiency resulting from correction of an adverse displacement ratio. A novel recovery mechanism is identified in which the polymer increases the ratio of viscous to gravity forces, reducing the water slumping. This leads to improved vertical sweep, recovering oil from regions of high oil saturation at the top of the reservoir. We simulated polymer flooding including temperature effects. Comparison of waterflood simulations including temperature effects with conventional isothermal simulations shows that, counter to normal expectations, isothermal simulations can underpredict recovery by > 10%.
CO2-Foam Field Test at the East Vacuum Grayburg/San Andres Unit
Authors: Martin F. D. , Stevens J. E. , Harpole K. J.
Published: December 2007

This paper summarizes the response from foam injection in a pilot test conducted at the East Vacuum Grayburg/San Andres Unit (EVGSAU), including results of the reservoir characterization effort and an extensive monitoring program. The paper specifically presents (1) the positive injection-well response (documented with injectivity data and profile logs), (2) the positive production-well response, and (3) the economics of the foam test.
Screening of Oils for In-Situ Combustion at Reservoir Conditions by Accelerating-Rate Calorimetry
Authors: Yannimaras D. V. , Tiffin D. L.
Published: December 2007

This paper introduces a new method to screen crude oils for applicability of the air-injection/in-situ combustion process. Testing is performed at reservoir conditions, up to 41.4 MPa, with a specially modified accelerating-rate calorimeter (ARC™). ARC results are shown for four medium- and high-gravity oils, combustion-tube data is presented, and air-injection field data are discussed and compared. We interpret that the continuity of the ARC trace ties in kinetics, combustion-tube, and field air-injection results. Thus, a method is available to delimit the envelope of applicability of air-injection/in-situ combustion to those oil reservoirs where the probability of technical and economic success is greatest.
Steamflood Expansion Using Slim-Hole Injectors
Authors: Dennis E. L. , Johnson K. R. , Kirby R. H.
Published: December 2007

This paper describes a successful steam-injection vertical expansion recently implemented in California's Midway Sunset field with slim-hole injection wells. Slim-hole injectors were chosen over conventional injectors to reduce capital investment. The savings allowed drilling of additional injection wells, which were used to optimize steam placement on the basis of reservoir architecture. Two vertical expansion designs were compared at a fixed cost with either conventional or slim-hole steam injectors. The conventional well design had 10 injection wells and three temperature-observation wells. The steamdrive targets were two steeply dipping turbidite depositional lobes containing multiple, vertically segregated sand bodies. Selection of conventional well locations was based on the upper primary reservoir compromising injection location in the lower secondary reservoir. The slim-hole plan, consisting of 38 injectors and 10 temperature-observation wells, was selected because of its advantages. The capital cost for the slim-hole wells was about the same as the conventional program. Approximately three slim-hole injectors could be drilled for the cost of one conventional injector. With additional wells, injector locations were optimized for both the upper primary and lower secondary reservoirs. These additional injection wells provided improved profile control and steamflood management of the individual sand bodies within each reservoir. As a result of the vertical expansion, incremental production has increased steadily since project startup.
Glenn Pool Surfactant-Flood Expansion Project: A Technical Summary
Authors: Bae J. H.
Published: December 2007

After a successful pilot test, a 92-acre surfactant-flood expansion project was conducted in the William Berryhill lease of the Glenn Pool field, Creek County, OK. The field had been waterflooded and had an average residual oil saturation (ROS) of 30% PV. At the end of Oct. 1992, ≈ 1.14 million bbl of incremental oil was produced, which accounted for about one-third of the residual oil. This is the largest amount of oil produced by a surfactant flood.
Scaling of Multiphase Flow in Simple Heterogeneous Porous Media
Authors: Zhou Dengen , Fayers F. J. , Orr F. M.
Published: December 2007

The nature of flow in porous media is determined by the interaction of the physical properties of the medium and fluids, and by the interplay of various forces involved in the displacement process. Identifying flow regions at a given reservoir operating condition is a key issue in forecasting reservoir performance and hence of optimizing operations. This work identifies dominant flow regions at various conditions. Three dimensionless groups, NgvM/(1 + M) (gravity/viscous ratio), NcvM/(1 + M) (capillary/viscous ratio) and Ri2 (shape factor), are defined and used to resolve flow regions. The analysis shows that the relative magnitudes of forces involved in the system combined with the reservoir properties determine the flow region and fluid distribution in the medium.

By choosing appropriate ranges for the dimensionless numbers, recovery processes can be specified from the general theory, and the boundaries to flow regions confirmed by comparison with existing experimental and simulation results. Three commonly studied flow systems have been investigated, which are miscible displacements without dispersion (Ncv ≈ 0) in layered reservoirs, immiscible displacements (Ngv ≈ 0) in layered and homogeneous media, and flow in highly fractured reservoirs.
On the Subject of Abnormally Pressured Gas Reservoirs
Authors: Hurst William
Published: December 2007

This is a discussion of SPE-2225-PA "Water Production from Abnormally Pressured Gas Reservoirs in South Louisiana", by W. E. Wallace, published in the Aug., 1969, issue of JPT.

In his paper on abnormally pressured gas reservoirs in South Louisiana, the main thesis as expressed by W. E. Wallace is that in high pressure gas fields much of the water produced with the gas results from the compaction of the shale from the weight of the overburden with the lowering of reservoir pressure to release water to be produced with the gas. This is his conclusion for several of the examples cited in his paper, and as he terms this, such is water produced from the shales and in-situ water resulting from the compressibility of the water within the reservoir.

If he wishes to approach it as such, I recognize that his thinking is that of the geologist whereas my interpretation is that of a reservoir engineer.

Mr. Wallace describes this water released as the compaction of the shale bodies, subject to the increasing weight of the overburden with the lowering in reservoir pressure. But I must ask, "To what extent does the weight of the overburden take effect?"
The Effect of Axial Tension on the Deflection of Centralized Casing
Authors: Sutko A.A.
Published: December 2007

The midpoint deflection of centralized casing is often calculated using the equation for a uniformly loaded beam with two fixed ends:

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

where y M is the maximum deflection (excluding that of the centralizers themselves), w the weight per unit length of casing, L the distance between centralizers, E the modulus of elasticity, I the moment of inertia of the casing cross-section, and 0, the hole angle. The units are pounds, degrees and either feet or inches. At least two service companies use this equation in their literature. Although Eq. 1 takes into account the casing weight and strength, it does not consider the tension in the casing. This tension, which is due to the weight of the casing below, reduces the casing deflection just as the sag in a rope or cable is lessened if the rope or cable is more tightly stretched. The equation for the maximum deflection of cable loaded under its own weight, is

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

where y T is the maximum deflection and T is thew L tension. Substituting a power series for cosh and2 T simplifying leads, for our purposes, to the following form:

......(3)

Using Eqs. 1 and 3, it is possible to describe a method that includes the effect of both the strength properties and the tension in the calculation of the properties and the tension in the calculation of the maximum deflection of centralized casing. The method is as follows:1. Calculate the casing deflection using Eq. 1.2. Assume that this deflection exists in a cable and using Eq. 3, calculate the tension that would be present. present. 3. Add to this tension the actual tension, T A, in the casing (using either an estimated value or one calculated as outlined in Ref. 2).4. Calculate the actual casing deflection by using a form of Eq. 3.

......(4)

A quicker way to get an idea of be general effect of including tension can be obtained by combining Eqs. 1, 3, and 4:

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

y r T L Fig. 1 is a plot of vs . For many oilfieldy M 48 EIy r applications is about 0.85 to 0.90 or higher.y M

P. 7
Methods for Numerical Simulation of Water and Gas Coning
Authors: MacDonald R.C.
Published: December 2007

This paper describes and evaluates three numerical methods for the simulation of well coning behavior. The first method employs the implicit pressure-explicit saturation (IMPES) analysis with pressure-explicit saturation (IMPES) analysis with the production terms treated implicitly. The second technique is similar to the first model except that the interblock transmissibilities are also treated implicitly in the saturation equation. The third model is fully implicitly with respect to all variables in a manner qualified in the introduction and utilizes simultaneous solution of the difference equations describing the multiphase flow. The use of implicit transmissibilities in the IMPES model results in a several-fold increase in the allowable time-increment size over that attainable with the implicit production IMPES scheme, while the computing time per step is increased by less than 10 percent. The fully implicit model accepts larger time-increment sizes than possible with the first two methods but requires 3.3 times the computing time per time step needed by the second model. The fully implicit model is substantially more efficient for problems involving high capillary forces (treated explicitly in the IMPES methods) and small computing grid blocks at the wellbore. In problems involving moderate capillary forces and larger grid spacings, the fully implicit method and the implicit transmissibility IMPES technique are comparable in computing efficiency. The results of three coning studies are presented: a water-oil problem, a three-phase coning presented: a water-oil problem, a three-phase coning example, and a comparison of simulation results with a laboratory coning experiment. Also presented is an analysis of truncation error and a comparison of computational work requirements.

Introduction

This study was performed to evaluate three finite-difference schemes for simulating well coning behavior. The basis for this evaluation was the IMPES (implicit pressure-explicit saturation) model with explicit transmissibilities and implicit production terms. This model is referred to hereafter production terms. This model is referred to hereafter as Model 1. The next model evaluated in this work is an IMPES model similar to Model 1, except that the saturation-dependent interblock transmissibilities are treated implicitly rather than explicitly in the saturation equation. The third model is fully implicitly with respect to all variables and terms transmissibilities, pressure, saturation an capillary pressure - and utilizes simultaneous solution of the difference equations describing the multiphase flow. These two models are referred to hereafter simply as Model 2 and Model 3. For the purpose of clarity all models are described in purpose of clarity all models are described in reference to the problem of incompressible, two-phase flow. The techniques are equally applicable, however, to compressible, three-phase flow models. The examples chosen for illustration employ both incompressible and compressible simulation models.

SPEJ

p. 425
A Formula for the Successful Management of Drilling Information
Authors: Magner M. J. , Booth J. E. , Williams J. W.
Published: December 2007

Many drilling information systems have come and gone over the past decade. Some systems were very sophisticated because they used the latest technologies and human interfaces. Many factors about these systems and their implementation, however, proved to be weak points. In some cases, the system may have been too expensive to develop and/or maintain, too difficult to use, or simply did not meet the client's business need.

The Mobil Drilling Data Center (DDC) is a successful drilling information management system that has been in continuous operation for 13 years. This paper outlines key factors that have made the DDC one of the industry's most comprehensive and long-lived drilling information systems.
Design and Development of An Artificial Neural Network for Estimation of Formation Permeability
Authors: Mohaghegh Shahab , Arefi Reza , Bilgesu Ilkin , Ameri Samuel , Rose Deanna
Published: December 2007

Permeability is one of the most important characteristics of hydrocarbon-bearing formations and one of the most important pieces of information in the design and management of enhanced recovery operations. With accurate knowledge of permeability, petroleum engineers can manage the production process of a field efficiently. Although formation permeability is often measured in the laboratory from cores or evaluated from well-test data, core analysis and well-test data are only available from a few wells in a field, while the majority of wells are logged.

In this study, we have designed an artificial neural network that can accurately predict the permeability of the formations by use of the data provided by geophysical well logs. Artificial neural network, a biologically inspired computing method which has an ability to learn, self-adjust, and be trained, provides a powerful tool in solving pattern recognition problems.

In the past, others have attempted to use well logs to predict permeability.1 The problems with previous approaches, however, were two-fold: the limited number of variables (only one variable— porosity) and the use of regression analysis as the main tool for correlations. The approach introduced in this paper attempts to overcome these shortcomings. We do this by first, using many variables from well logs that may provide information about the permeability, and second, recognizing the existence of possible patterns between these variables and formation permeability by use of artificial neural networks. Neural nets are analog, inherently parallel, distributive systems. These characteristics enable artificial neural networks to be successful in predicting the formation permeability in rocks from well-log data.
Adaptation of Reservoir Engineering Software to a DOS/Linux PC
Authors: Emanuel A. S. , Jones R. C. , McWilliams R. S. , Tsaio J. C.
Published: December 2007

Recent publications have described the implementation of state-of-the-art reservoir engineering applications based on integrated networks of mainframe, workstation, and desktop computers. These facilities provide excellent resources for geologic and engineering applications, but at the cost of substantial investment in computer hardware, network installation, and systems staffing. This paper describes an adaptation of similar state-of-the-art applications to a desktop platform that minimizes the required hardware and system investment.

The platform is an Intel 486 or Pentium-based PC with two hard drives and 32 to 64 MB of memory. One disk is partitioned to a standard DOS/Windows environment. The other disk is partitioned to the Linux operating system. Linux is a freely available clone of Unix for the 80386/80486 CPU, which is supported by a worldwide volunteer effort. A machine of this type can be constructed from components for $4,000 to $8,000, depending on CPU and memory. A number of proprietary modeling codes have been ported over so that the PC can provide much of the capability of the network systems.

On the Linux disk, there are interactive graphics codes for log analysis, geostatistical reservoir characterization, mapping geologic data into reservoir models, streamtube modeling, and scale up of fine-grid models to coarse grid. On the DOS disk, there are the typical vender-supplied applications for pressure-transient analysis, production analysis, spreadsheet processing, and word processing. A proprietary, general-purpose 3D reservoir simulator is available under both DOS and Linux. The PC can be both networked on the DOS and Linux sides or run stand-alone. If networked, Linux can also provide an X-terminal facility to other Unix or Linux workstations. The PC is sufficiently fast to provide geostatistical processing for reservoirs of several hundred wells. With 64 MB of memory, finite-difference models of up to 20,000 gridblocks can be accommodated for a two-phase, black oil formulation. Using streamtube and hybrid simulation techniques, reservoir models incorporating 300 to 400 wells are practical. We have found the DOS/Linux PC to be useful in several niche situations: remote locations where there is no network, locations where there is insufficient capital budget for a workstation, and locations where network charges are insupportable or the workstations are overloaded.
A RAD Approach to Client/Server System Development
Authors: Brulé Mike , Fair Walt , Jiang Jun , Sanvido Ron
Published: December 2007

The capability, richness, and leverage of inexpensive commercial operating systems, off-the-shelf applications, and powerful development tools have made building feature-rich client/server systems possible in rapid time and at low cost—ushering in a new level of systems integration not before possible. We achieve rapid application development (RAD) by using a flexible and extendible client/server integration framework. The framework provides the means to integrate in-house and third-party software applications with databases and expert-system knowledge bases and, where appropriate, provides communication links among the applications. We discuss the integration framework's capabilities, explain its underlying system architecture, and outline the methods and tools used to customize and integrate many diverse applications.
A 3D Analysis of a Bottomhole Assembly Under Large Deflection
Authors: Li Zifeng , Ma Xingrui , Huang Wenhu , Liu Xisheng
Published: December 2007

A 3D static mathematical model of a bottomhole assembly (BHA) including steerable downhole motor assembly under large deflection has been established. The forces and deflections of the drillstring have been accurately computed by making use of the method of weighted residuals, the weighted objective function, and the method of optimization to calculate the tangency point and to reduce the effect of the indistinct tangency point conditions. The effects of the weight on bit, the borehole geometry, the geometry and tool face rotation of the BHA on the bit building, and right walking force have been studied separately. There is a significant difference between the bit forces of large deflection analysis and small deflection analysis.
Real-Time Job Monitoring and Performance Control of Primary Cementing Operations as a Way to Total Quality Management
Authors: Spoerker H. F.
Published: December 2007

A high-accuracy wellsite mud-logging system was developed and implemented to compare standpipe pressures and annular flow rates during primary cementing operations with real-time predictions from a hydraulic simulation model. This paper investigates the development of possible cementing job execution problems, such as low (laminar) flow rates in the annulus at critical job stages, resulting in unsatisfactory mud displacement and ultimately inadequate zonal isolation. Ways to eliminate or at least control free-fall-induced problems through hydraulic simulation at the rigsite and comparison with real-time job parameters, such as pump rates, standpipe pressures, and annular return rates, are presented with detailed descriptions of tested flowmeter equipment and logging experience gained during field testing. Several case studies are presented that compare predictions from job simulation with recorded data (flow-in/-out and standpipe pressure) highlighting special trends, such as fracturing formations, caused by excessive equivalent circulating densities (ECD's) during free-fall conditions.
Optimum Position for Wells Producing at Constant Wellbore Pressure
Authors: Camacho-V Rodolfo , Rodríguez Fernando , Galindo-N Agustín , Prats Michael
Published: December 2007

This paper deals with the determination of the optimum position of several wells, producing at constant different wellbore pressures from a two-dimensional closed -boundary reservoirs, to maximize the cumulative production or the total flow rate. To achieve this objective we use an improved version of the analytical solution recently proposed by Rodriguez and Cinco-Ley1 and an optimization algorithm based on a quasi-Newton procedure with line search. At each iteration the algorithm approximates the negative of the objective function by a quadratic relation derived from a Taylor series.

The improvement of Rodríguez and Cinco's solution1 is attained in four ways. First, an approximation is obtained, which works better at earlier times (before the boundary dominated period starts) than the previous solution. Second, the infinite sums that are present in the solution are expressed in a condensed form, which is relevant for reducing the computer time when the optimization algorithm is used. Third, the solution is modified to take into account the possibility of having wells starting to produce at different times. This point allows us to deal with the problem of getting the optimum position for an infill drilling program. Last, the solution is extended to include the possibility of changing the value of wellbore pressure or being able to stimulate any of the wells at any time.

When the wells are producing at different wellbore pressures it is found that the optimum position is a function of time, otherwise the optimum position is fixed.
Further Advances in Coiled-Tubing Drilling
Authors: Eide Egil , Brinkhorst Jan , Volker Heinz , Burge Phil , Ewen R.L.
Published: December 2007

The use of coiled tubing (CT) to drill horizontal re-entry wells has received considerable interest in the industry over the last two years. The benefit of being able to drill at balance, safely and in a controlled manner, with nitrogen to reduce downhole pressure while drilling highly depleted reservoirs, provides an advantage over conventional techniques, particularly in reducing formation damage. This paper describes such a horizontal re-entry drilled in the shallow depleted waterflooded reservoir Barenburg in northern Germany. The scope of work for this project included (1) cutting windows through 6 5/8- and 9 5/8-in. casing, (2) drilling a 5 7/8-in.-medium-radius curve, (3) running a 5-in. liner and a 5½-in. parasitic string for nitrogen injection, (4) drilling a 4 3/8-in. horizontal with nitrogen to maintain a balanced condition, (5) running openhole logs, and (6) running 3½-in. slotted liner. The entire program was executed with no intervention from a conventional rig or workover hoist. A special structure to be positioned over the well to support the CT injector head and to provide a work platform had to be constructed for this type of operation. A dedicated mast for lifting pipe and downhole tools was placed on the substructure. The development of a surface-controlled orienting tool and an adjustable motor provided excellent directional capabilities on a 2 3/8-in. CT. This program represents a significant extension of the capabilities of drilling with CT.

Introduction

Over the last 2 years, a number of oil companies have gained experience with CT drilling that has been carried out mainly as re-entry operations. Encouraging results have been reported that generated the idea to develop this technology further as an integrated package capable of carrying out the entire operation without the intervention of a conventional rig or workover hoist. Because no service company on the market could provide the entire scope of work, BEB Erdgas & Erdol GmbH decided to cooperate with two companies on a partnership basis to develop required tools and equipment. A trust was formed between the two service companies for this project.
A Unified Approach to Asphaltene Precipitation: Laboratory Measurement and Modeling
Authors: MacMillan D.J. , Tackett J.E. , Jessee M.A. , Monger-McClure T.G.
Published: December 2007

A unified approach to evaluating asphaltene precipitation based on laboratory measurement and modeling is presented. This approach used an organic deposition cell for measuring asphaltene drop out onset conditions. Asphaltene precipitation was detected by changes in optical fluorescence, electrical conductance, and visual observation. A series of experiments measured the effects of changing pressure, temperature and composition on asphaltene precipitation. A fully-compositional V-L-S mathematical model completed the analysis by matching the experimental results. The model was then used to forecast asphaltene precipitation under a variety of production scenarios including response to gas-lift operations, and to evaluate the possible location of a tar-mat.

Introduction

An organic deposition cell (ODC) was developed to experimentally detect asphaltene drop out onset. Two different detection techniques were incorporated into the cell. Fluorescence spectrometry has been used to study aromatic compounds. Fiber optics allowed application of this basic technique to asphaltene detection in the ODC. Conductance measurements were also incorporated into the ODC.

Thermodynamic models have been used to predict asphaltene precipitation from reservoir crudes under a variety of conditions. Burke et al and others applied polymer solution theory to the prediction of asphaltene precipitation. While this technique has been very successful, it is limited in its capability to predict the amount of asphaltene precipitate and varying precipitate composition. It was therefore decided to use the more rigorous approach presented by Thomas et al to model asphaltene precipitation. This method is based on an earlier wax deposition model which allows a fully compositional representation of the asphaltene phase.

EXPERIMENTAL TECHNIQUES

The high-pressure (6000 psig) I high-temperature (250 F) ODC employed a piston to allow sample or chemical introduction and pressure/volume control(Figure 1). The piston was designed to minimize dead volume so that flashing during sample introduction was reduced. Heating elements and cooling coils were installed for temperature control. The sapphire window allowed limited visual inspection and the use of a flexible fiber optics probe for luminescence detection. The cell was rocked to allow sample mixing and could be inverted so the window was on top. Electrical conductance was measured between the cellwall and the conducting probe. The conductance values obtained included a high background contribution from the equipment.
High-Throughput TVD-Based Simulation of Tracer Flow
Authors: Wattenbarger Robert C. , Aziz Khalid , Orr F. M.
Published: December 2007

High-throughput, total-variation-diminishing based, numerical techniques for simulating tracer flow are developed. High-throughput (HT) timestepping enables explicit differencing techniques to use timesteps that are larger than allowed by normal stability constraints. Total-variation-diminishing (TVD) based techniques are a means of controlling the solution oscillations associated with high-order differencing schemes. The concept of ‘upstream stability’ is introduced to help combine HT timestepping with TVD-based differencing. Additionally, an improved HT timestepping algorithm for solving physically dispersive flow problems is developed.

Numerical experiments indicate that HT timestepping is most beneficial for solving highly convective flows that have both a physical Peclet number and a diffusion-only numerical Peclet number greater than one. Experiments comparing standard and alternating direction TVD-based techniques with both the Superbee (SB) and third-order based (L3) limiters indicate that the TVD-SB scheme is the most accurate for purely convective problems. For physically dispersive problems, the TVD-SB scheme may be too compressive and the TVD-L3 is recommended. The alternating direction TVD scheme is the least sensitive to timestepping and the most sensitive to grid-orientation.
Simulation of a North Sea Field Experiencing Significant Compaction Drive
Authors: Cook C. C. , Jewell Stephen
Published: December 2007

The Valhall field in the Norwegian North Sea is a high-porosity chalk reservoir undergoing primary pressure depletion. Over the last 10 years there have been a number of computer modeling studies of the field which have all assumed an original oil-in-place of approximately 2,000 MMSTB (318.0 × 106 m3). Despite this basic similarity, estimates of ultimate recoverable reserves have increased from an initial value of 200 MMSTB (31.8 × 106 m3) to the present estimate of 500 MMSTB (79.5 × 106 m3). This increase is partly due to the addition of wells and the optimization of completion techniques. However, the single most important and unique feature influencing Valhall long-term production performance is reservoir rock compaction.

Recent simulation studies indicate that over half of the oil produced from the Valhall reservoir is a direct result of the rock compaction recovery mechanism. In the reservoir crest area rock compressibilities can be as high as 150 × 10−6 psi−1 (21.75 × 10−6 kPa−1), and it is estimated that compaction contributes over 70% of hydrocarbon recoveries.

This paper describes the mathematical model used to simulate reservoir performance in a compacting reservoir with specific discussion regarding the proportion of oil produced by each physical recovery process. An understanding of the recovery mechanisms and their relative importance is critical for the successful management of the field. This paper also presents an alternative method for evaluating the various recovery processes using a simple solution to the material-balance equation. This is used to substantiate the magnitude of the various recovery mechanisms identified in the simulation model.
Effect of Rock Heterogeneity on Relative Permeability: Implications for Scale-up
Authors: Honarpour M.M. , Cullick A.S. , Saad Naji , Humphreys N.V.
Published: December 2007

Relative permeability and capillary pressure are important parameters in reservoir engineering calculations and numerical simulation of reservoir performance. Heterogeneities are often avoided during core plug screening and selection for relative permeability and capillary pressure measurements. However, sandstone rocks in many depositional environments show significant small-scale laminations that affect the measured relative permeability. This report demonstrates the length scale dependence of relative permeability data that results from cm to mm scale rock laminations and patterns of initial and final oil saturation distribution in a 108-cm long laminated core. It shows in a quantitative way the capillary, trapping of water in low-permeability lamina during primary drainage and of oil in high permeability lamina during water imbibition. Steady-state water-oil imbibition relative permeability data and unsteady-state drainage and imbibition data were collected using linear x-ray and x-ray CT scanning for in situ fluid saturation measurement. Numerical simulations of the core floods show that relative permeabilities and capillary pressures that are correlated with small-scale differences in porosity and permeability are necessary to reproduce the observed saturation distributions. Thus, the relative permeability length-scale dependence, combined with anisotropy data presented elsewhere (SPE 27968), imply that scaled-up effective relative permeability must account properly for heterogeneity. Assignment of core-plug relative permeability to simulator grid blocks may not capture the correct effective fluid flow performance in rocks that are heterogeneous with correlation length greater than the plug dimensions, and thus lead to erroneous fluid flow performance predictions.

Using numerical simulation, a number of papers have reported the importance of core-scale geologic heterogeneity to relative permeability and its ultimate impact to the prediction of reservoir-scale flow behavior. Jones et al. showed that within a channel environment the choice of relative permeability scale-up from small-scale to larger scales is very important to accurate prediction of water breakthrough and produced oil volume and is more important than are spatial arrangement of lithofacies within channel sandbodies.
An Analysis for Predicting the Performance of Cone-Shaped Reservoirs Receiving Gas or Water Injection
Authors: Welge H.J. , Johnson E.F. , Hicks A.L. , Brinkman F.H.
Published: December 2007

A method is presented for predicting the character of gas or water displacement in a radial system, which can be either horizontal or inclined. The latter case would comprise cone-shaped or dome-shaped symmetry. The method considers the one dimension of radial distance, taken parallel to the bedding planes. Approximate allowance can be made for segregation of the two fluids perpendicular to the bedding planes. A complete saturation history can be obtained in about a day's time with the use of a desk calculator. Results of an example calculation agree well with the performance of simulated gas drive in a large model representing a section of a cone. This pie-shaped, sand-packed model was 8-ft long and 4-in. thick. The method of solution is useful in handling other partial differential equations of first order and first degree.

Introduction

A new analytical method has been developed for predicting the performance of gas or water drive in a reservoir having radial or cone-shaped symmetry (see Fig. 1). In addition, this new development offers a general method of handling partial differential equations of first order and first degree. This work extends those methods developed previously for predicting the displacement of oil by gas or water in linear systems. The method of calculating oil recovery in a radial system involves two major parts. The first part is a calculation of the distribution of saturations at various times of depletion. The second part is the calculation of oil recovery and producing gas-oil or water-oil ratios through volumetric balance on the saturation distributions obtained in the first part. This second part differs only slightly in principle from similar calculations made with linear systems, for instance. The basic assumptions used in the calculations are as follows.One-dimensional radial flow. An approach is explained later for approximating a second vertical dimension. (Withdrawals of oil, and of the driving fluid after breakthrough, are assumed uniform around the periphery of the dome.)Constant-volume fluid flow. Thus, in a gas drive there is no change in gas solubility, or in oil or gas volume due to viscous and gravity pressure drops.Capillary forces are negligible.Constant rate of injection.

A program has been written for carrying out the calculations needed on a digital computer. However, a prediction can also be arrived at using a desk calculator; this latter method of work requires about a day's time for each prediction made.

CALCULATION OF SATURATION DISTRIBUTION

For definiteness, we describe the development of our method for the case of gas drive from the crest of the structure. The reader will note, however, that the method is just as applicable to an advancing radial water drive.

JPT

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