bluuebunny/crossref_metadata_2025 huggingface dataset:
The Effect of Temperature and Pressure on the Viscosity of Oil-Base Muds
Authors: McMordie W.C. , Bennett R.B. , Bland R.G.
Published: December 2007

Introduction

The viscosity of oil-base muds can be determined over a wide range of temperature and pressure using the BHC Viscometer. This instrument consists of two concentric cylinders mounted in a 20,000-psig autoclave that has an upper operating-temperature limit of 650 degrees F. The inner cylinder, or rotor, is connected by a magnetic couple to a Haake Rotovisko. A detailed description of the instrument has been published previously.

In operating the BHC Viscometer, the autoclave is completely filled with mud and sealed. The rotor is rotated at a constant rate and the sample is allowed to reach an equilibrium temperature. The pressure is then adjusted with an auxiliary pump and the shear stress is recorded for each shear rate.

The instrument was calibrated by first calculating the shear rates from the viscometer dimensions. This method gave shear rates of 11, 21, 32, 64, 96, 191, 286, 573, and 860 sec-1. The mean shear-stress constant was then determined experimentally to be 8.1 dynes/cm2/scale part (1.6 lb/100 ft2/scale part).

Discussion

The best mathematical description of the viscosity of an oil-base mud at constant temperature and pressure is the power-law model. The linear form of this model is power-law model. The linear form of this model is(1)ln = ln K + n ln y

However, two sets of constants are required, one set for use at shear rates below ~ 200 sec and the other set for the higher shear rates.

The analysis of the pressure and temperature effects shows that the logarithm of the shear stress is directly proportional to the pressure and inversely proportional to proportional to the pressure and inversely proportional to the temperature. These relationships can be expressed by the following equations:(2)ln p,

JPT

P. 884
A Coupled Reservoir and Geomechanical Simulation System
Authors: Settari Antonin , Mounts F. M.
Published: December 2007

Current simulation models do not account for the interactions among the geomechanical behavior, formation fracturing and multiphase flow, and heat transfer in porous media. This paper describes a method for modular coupling of a commercial reservoir simulator with a three-dimensional (3D) stress code and fracture-propagation model. The iteratively coupled system is equivalent to a fully coupled solution of flow and stress. The iterative method is very robust. An experience with acceleration of the iteration is described, and the utility of the method is demonstrated on examples. The comparison with an uncoupled solution shows that significantly different (and more realistic) answers are obtained with the coupled modeling. The current limitations and future work are also discussed.
Vapex: An Efficient Process for the Recovery of Heavy Oil and Bitumen
Authors: Das S. K.
Published: December 2007

The Vapex (vapor extraction) process may be a viable technique for the recovery of highly viscous heavy oil and bitumen. The size of the estimated heavy oil and tar sand resources in the United States amounts to 100 billion bbl and 62 billion bbl of oil in place (OIP), respectively. Although this represents a small fraction of the total world reserves, it is about one-third of the total estimated crude oil discovered in the United States. The world estimate of this resource is about 6 trillion bbl, six times the conventional oil reserves, and may be the future source of energy. Efficient extraction of these highly viscous crude oils poses a serious challenge to petroleum engineers. In some of the heavy oil reservoirs steam flooding and in-situ combustion processes were partially successful. For thick tar sand reservoirs, the steam-assisted gravity drainage (SAGD) process proved to be effective. However, thermal processes, in addition to other disadvantages, suffer from energy inefficiency caused by heat losses.

The Vapex process involves injection of vaporized hydrocarbon solvents into heavy oil and bitumen reservoirs; the solvent-diluted oi1 drains by gravity to a horizontal production well. Recent research has shown that the process is highly energy efficient, environmentally friendly, causes in-situ upgrading, and requires low capital investment compared to its competitive process, SAGD. The applicability of the Vapex process may even surpass SAGD in thin reservoirs, reservoirs underlain by aquifer, offshore operations, etc. Some experimental results, a theoretical analysis, and the feasibility of this process for implementation in heavy oil and bitumen reservoirs will be presented.
World's First 4.5-in. Coiled-Tubing Pipeline
Authors: El-laithy W. F.
Published: December 2007

Coiled tubing (CT) is a rapidly growing pipeline technology. Use of CT as pipeline is a new application to an existing technology. Until recently, CT was primarily used by service companies for CT workovers. As the technology expanded, the industry began using CT for other applications such as drilling, coring, logging, well cleanout operations, and artificial lift. As the tubing mills began producing larger sizes, the use of CT as pipelines was considered possible. The application of CT as a pipeline began in the Gulf of Mexico. The early results supported the application as being a low cost, time saving, economic alternative to conventional welded pipe for flowlines. CT applications have been used in 4 to 100 ft of water in the Gulf of Mexico area and the installation techniques have varied significantly.

In 1994, the Gulf of Suez Petroleum Co. (Gupco), a joint venture company between Amoco Production Co. and the Egyptian Petroleum Co., embarked on the first international application of the 3.5-in. coiled pipe with a dynamic lay procedure. The cost savings from the first two jobs were estimated to be in excess of 70% when compared to the traditional lay vessel charges. Ref. 1 presents engineering design and field experience. Subsequently, Gupco has taken a leading role in the application of CT technology with the 1996 installations of the first production of 4.5-in. coiled pipe, one of which is a record-setting 62,000-ft high-pressure water supply line. Cost savings of this larger diameter pipe are still yielding 55% over the conventional barge lay techniques. In this paper, we will cover the significant findings of that engineering work and present actual field case histories on Egypt's first 4.5-in. coiled pipeline projects.
Analytical Solutions for Waterfloods in Fractured Reservoirs Obtained by an Asymptotic Approximation
Authors: Rasmussen M. L. , Civan Faruk
Published: December 2007

This analysis presents an approximation for the long-time evaluation of waterfloods in fractured reservoirs. The formulas for the approximate solution are easier to use than the exact results and lend themselves to the physical description of the propagation speed and the diffusive spreading of the wave front. A comparison of the approximate and exact results for a representative example shows excellent correlation, and the differences are well within the accuracy that can be expected in the practical representation of reservoir parameters.
Composite Production Riser—Testing and Qualification
Authors: Salama M. M. , Johnson D. B. , Long J. R.
Published: December 2007

The production riser is a tension leg platform (TLP) component that lends itself to taking advantage of the unique properties of advanced composite materials. A composite production riser (CPR) has the potential to reduce capital expenditure and improve reliability for development of reservoirs in deep water because of its lighter weight, improved corrosion resistance, and excellent fatigue performance compared with steel risers. In 1995, a project was organized by several oil, service, and composite manufacturing companies and partially sponsored by the U.S. Dept. of Commerce Natl. Inst. of Standards and Technology Advanced Technology Program to develop a cost effective CPR for deepwater applications and to overcome the technical challenges in design, analysis, fabrication, and qualification of a CPR. A critical element of this project is the specification and implementation of a comprehensive testing program to confirm the advantages, validate the design, and establish the long-term performance of a CPR as well as to secure the confidence of both operational staff and certifying authorities. The testing program was designed to identify performance limitations, establish the failure envelope for the full-diameter CPR joints, and verify that the manufactured CPR meets the performance requirements for application on a TLP in the Gulf of Mexico. In addition, the testing program, combined with the analytical effort, was planned to establish statistical variations in strength factors and to generate data to design CPR's of different sizes and for different operating conditions. This will allow for site-specific qualification of a CPR with minimal testing. In this paper, we discuss the testing program, review its rationale, and present currently available results. Test results clearly illustrate that current state-of-practice for design and manufacturing of composite CPR joints are well advanced to achieve the required cost effectiveness and high reliability for use in deepwater developments.
Effect of Underinhibition With Methanol and Ethylene Glycol on the Hydrate-Control Process
Authors: Yousif M. H.
Published: December 2007

Hydrate control can be achieved by chemical injection. Currently, methanol and ethylene glycol are the most widely used inhibitors in offshore hydrate control operations. To achieve effective hydrate inhibition, a sufficient amount of inhibitor must be injected to shift the thermodynamic equilibrium condition for hydrate formation outside the pipeline operating pressure and temperature. Recently published field experiments showed that hydrate blockages form more readily in underinhibited systems than in systems completely without inhibitor. A laboratory study is conducted to determine the effect of low concentration (1 to 5 wt%) methanol and ethylene glycol on the hydrate formation process. The results show that, although these chemicals are effective hydrate inhibitors when added in sufficient quantities, they actually enhance the rate of hydrate formation when added at low concentrations to the water. Furthermore, the presence of these chemicals seems to affect the size of the forming hydrate particles.
Delineation of Air/Water Capillary Transition Zone From GPR Data
Authors: Nguyen Buu-Long , Bruining Johannes , Slob E. C. , Hopman Victor
Published: December 2007

Spilled petroleum products spread laterally in the capillary transition zone above the water table. Ground penetrating radar (GPR) is a technique that can potentially delineate the air/water capillary transition zone (CTZ), because a varying water content strongly influences the reflected signal through its effect on the electrical properties. The vertical water distribution is determined on the pore scale by the grain size distribution and on the reservoir scale, mainly, by the permeability distribution. We present the integral equations for the reflected signal from a inhomogeneous slab with a depth-dependent dielectric constant and electrical conductivity. The numerical solution of the equations allows us to compute the signal reflected from different sand profiles. The results show that the reflected signal is strongly influenced by both the grain size distribution and the variation in permeability. A strong frequency dependence is also observed. We present a two-dimensional GPR profile measured in the field that shows a clear effect of the CTZ on the reflection of the radar signal. All these results are considered of importance for the interpretation of GPR data involving the capillary transition zone.
The Athel: A Challenging Formation in South Oman
Authors: O'Dell P. M.
Published: December 2007

The Athel silicilyte is a deep, tight formation containing light oil and dissolved sour gas. Because the potential volume is large, there is interest in early development. However, because individual wells are very expensive, every opportunity to gather information must be used. Well testing (production tests, pressure/volume/temperature (PVT) sampling, production logging runs, and pressure transient tests) has been used extensively to characterize the reservoir, to guide appraisal activities, and to shape the ultimate development. Key issues to be resolved before development are initial and sustained productivity and project costs.

Production tests have demonstrated both challenges and opportunities in producing from this unique formation. Pressure transient tests have indicated that effective reservoir permeability is one-tenth of cleaned core plug permeability. The difference is likely caused by some combination of sealed fractures and the plugging effects of bitumen in the reservoir. Production logging has been used to measure the fraction of pay contributing to production. Reservoir simulation models, based on well test results, have been used to predict initial rates and ultimate recoveries for various well types (vertical, multiple drainhole, and multiple hydraulic fractures). Project costs (number of wells required) are based on these reservoir simulation results.
Rig Site and Laboratory Use of CWT Acoustic Velocity Measurements on Cuttings
Authors: Nes O. -M. , Horsrud Per , SØnstebØ E. F. , Holt R. M. , Ese A. M. , Økland Dag , KjØrholt Halvor
Published: December 2007

A continuous wave technique (CWT) for measurement of acoustic phase velocities on cuttings is presented. The equipment is particularly well suited for testing of small samples like cuttings, and measurements, even on sub-mm-thick shale cuttings, have been performed. This yields potential access to a new source of data on the drilled formation that can also be attained in quasireal time at the rig site. The prototype equipment developed is portable, fast, and easy to use. Tests have been performed both at the rig site and in the laboratory. Potential applications include estimation of mechanical properties of shales, effects of various fluids and drilling muds, estimation of seismic parameters, and estimation of pore pressure.
Data Validation: Key to Development of an Integrated Reservoir Model for the Wara Formation, Greater Burgan Field
Authors: Pederson J. M. , Moon M. S. , Al-Ajeel H. Y.
Published: December 2007

Prior coarse grid simulation models in the Greater Burgan field were unable to capture the stratigraphically diverse nature of the Wara reservoir and accurately match the existing historical data, resulting in unrealistic predictions of fluid flow from individual reservoir layers. Most simulation failures are blamed on the inability to correctly model reservoir heterogeneity rather than problems associated with the data it is trying to match. In reality it is probably a function of both. In this paper, we emphasize the importance of a systematic review of historical production data to ensure the accurate initialization of a simulation model and to assess whether a full history match should or should not be undertaken.

Not only does there need to be sufficient geologic and engineering detail to accurately characterize the fluid and flow properties of the Wara reservoir, but, more importantly, issues involving the validity, accuracy, and lack of historic data need to be addressed before deciding whether a reasonable reservoir model for history match can be developed. The reservoir size, long history, and high production rates of the Greater Burgan field magnify the impact and highlight the importance of correcting data errors and recognizing data uncertainty and gaps.
Compositional and Black Oil Reservoir Simulation
Authors: Coats K. H. , Thomas L. K. , Pierson R. G.
Published: December 2007

This paper describes a three-dimensional (3D), three-phase reservoir simulation model for black oil and compositional applications. Both implicit pressure, explicit saturation/concentration (IMPES) and fully implicit formulations are included. The relaxed volume balance concept effectively conserves mass and volume and reduces Newton iterations in both formulations. A new implicit well rate calculation method improves IMPES stability. It approximates wellbore crossflow effects with high efficiency and relative simplicity in both IMPES and fully implicit formulations. Multiphase flow in the tubing and near-well non-Darcy gas flow effects are treated implicitly.

Initial saturations are calculated as a function of water/oil and gas/oil capillary pressures, which are optionally dependent upon the Leverett J function. A normalization of the relative permeability and capillary pressure curves is used to calculate these terms as a function of rock type and gridblock residual saturations.

Example problems are presented, including several of the SPE comparative solution problems and field simulations.
A Hybrid Markov Chain Monte Carlo Method for Generating Permeability Fields Conditioned to Multiwell Pressure Data and Prior Information
Authors: Bonet-Cunha Luciane , Oliver D. S. , Redner R. A. , Reynolds A. C.
Published: December 2007

It is necessary to construct and sample the a posteriori probability density functions (pdf's) for the rock property fields to properly evaluate the uncertainty in reservoir performance predictions. In this work, the a posteriori pdf is constructed based on prior means and variograms (covariance function) for log-permeability and multiwell pressure data. Within the context of sampling the probability density function, we argue that the notion of equally probable realizations is the wrong paradigm for reservoir characterization. If the simulation of Gaussian random fields with a known variogram is the objective, it is shown that the variogram should not be incorporated directly into the objective function if simulated annealing (SA) is applied either to sample the a posteriori pdf or to estimate a global minimum of the associated objective function. It is shown that the hybrid Markov chain Monte Carlo (MCMC) method provides a way to explore more fully the set of plausible log-permeability fields and does not suffer from the high rejection rates of more standard MCMC methods.
Characterization of In-Situ Fluid Responses by Use of Optical Fluid Analysis
Authors: Felling M. M. , Morris C. W.
Published: December 2007

Experiments were performed to quantify the light transmittance and optical density (OD) characteristics of more than 75 fluid samples, including hydrocarbons, formation waters, drilling mud systems, mud filtrates, and mixtures of these fluids. A catalog of characteristic optical fluid analyzer (OFA, Schlumberger Wireline & Testing, Houston) responses has been developed to aid in real-time fluid identification applications. Hydrocarbon responses were found to show a strong correlation between oil gravity and OD. Downhole oil gravity can be estimated from the OFA response by comparison with the database. A new technique for minimizing oil sample contamination by various oil-base mud (OBM) filtrates is proposed. Furthermore, a means is suggested for distinguishing between OBM filtrates and formation hydrocarbons. Several field examples are presented to illustrate the application of the techniques introduced.
Succession-of-States Model for Calculating Long-Time Performance of Depletion Reservoirs
Authors: Lee K. S. , Miller M. A. , Sepehrnoori Kamy
Published: December 2007

This study presents a new finite-element approach for directly calculating pseudosteady-state flow behavior for wells in depletion systems. The approach allows for spatially dependent reservoir properties, complex reservoir geometries, and multiple wells. Results are verified against long-time transient solutions reported in the literature for several regularly shaped systems. The paper also demonstrates application of the approach to field-scale problems. Results show that this approach provides a fast and accurate method for modeling the long-time behavior of depletion reservoirs. The approach is particularly applicable to single-phase volumetric gas reservoirs.

A bounded reservoir with wells producing at constant rate will exhibit pseudo steady-state behavior after the end of typically short-lived infinite-acting and transition flow periods. This study develops a new approach for directly calculating pseudosteady-state flow behavior without solving the full time-dependent form of the diffusivity equation. This approach can be applied to the linearized forms of the diffusivity equation for either single-phase liquid or gas flow. A finite-element method is used that allows for spatially dependent reservoir properties, complex reservoir geometries, and multiple wells. The first part of this paper presents a verification of the approach by comparing results for some regularly shaped systems against full-transient solutions reported in the literature.

For the simulation of field-scale problems with multiple wells of differing production rates, a well model based on a near-wellbore approximation of the pseudopressure distribution during pseudosteady-state is introduced to reduce the concentration of elements near wells. The second part of the paper demonstrates application of the direct pseudosteady-state concept to actual reservoir problems. To account for rate changes during extended production periods, the pseudosteady-state equation was solved successively for each flow period and combined with an overall reservoir material balance analysis.

Results from this study show that this approach provides a fast and accurate method for modeling the long-time behavior of various types of reservoirs under depletion conditions. The approach is particularly applicable to single-phase volumetric gas reservoirs.
Design and Installation of a Cost-Effective Completion System for Horizontal Chalk Wells Where Multiple Zones Require Acid Stimulation
Authors: Thomson D. W. , Nazroo M. F.
Published: December 2007

An innovative completion design that allows multiple acid fractures to be performed in horizontal subsea chalk formation wells with a single trip into the wellbore has recently been codeveloped by a major North Sea operator and an oilfield engineering/manufacturing/service company. The project was begun to develop a system that would allow multiple acid stimulations to be efficiently performed in the shortest possible time in the North Sea Joanne field. The system ultimately developed allows acid stimulation of up to 10 different zones in a single trip with no through-tubing intervention. The first well in which this new technique was used had seven zones, and three additional wells with 10 zones each were later completed. This paper presents the development of this system and case histories of the first four subsea wells requiring stimulation.

The key element of the system is a multistage acid fracture (MSAF) tool that is similar to a sliding sleeve circulating device and is run in the closed position. Up to nine MSAF tools can be run in the completion with isolation of each zone being achieved by hydraulic-set retrievable packers that are positioned on each side of an MSAF tool. Each sleeve contains a threaded ball seat with the smallest ball seat in the lowest sleeve and the largest ball seat in the highest sleeve. With this system, stimulation of 10 separate zones is accomplished in 12 to 18 hours. A unique procedure that lubricates various sized, low specific gravity (SG) balls into the tubing and, then, pumps them to a mating seat in the appropriate MSAF tool to seal off the stimulated zone is used. This allows stimulation of the next zone, which is made accessible by opening the sleeve.

This technique provided a substantial reduction in the operation time normally required to stimulate multiple zones and allowed the stimulations to be precisely targeted within the reservoir. The case history data provides comparisons in operation times between traditional stimulations and this new method, as well as the significant enhancements to cost efficiency that resulted from its use. Additionally, this completion method allowed the stimulations to be designed and matched to the requirements of each reservoir zone, which provided the most cost-efficient treatments possible.
A Three-Layer Hydraulic Program for Effective Cuttings Transport and Hole Cleaning in Highly Deviated and Horizontal Wells
Authors: Nguyen Desmond , Rahman S. S.
Published: December 2007

A new mathematical model is presented that enables the prediction of various modes of cuttings transport in highly deviated to horizontal annuli that have been observed in laboratories. The model consists of three components: a bed of particles of uniform concentration, a dispersed layer in which particle concentration is varied, and a fluid-flow layer that could be a clear fluid or a turbulent suspension. The model predictions exhibit good agreement with experimental observations.
Measuring Compaction and Compressibilities in Unconsolidated Reservoir Materials by Time-Scaling Creep
Authors: Dudley J. W. , Myers M. T. , Shew R. D. , Arasteh M. M.
Published: December 2007

A testing procedure and analysis method is proposed that gives compaction and compressibility data that are independent of test duration for unconsolidated sands. Compaction data on unconsolidated sand material [including several Gulf of Mexico (GOM) reservoirs] derived from this method are presented. Tests on twin plugs give essentially the same stress-strain data for test durations from one day to three months. This occurs because of a fundamental time-scaling property of these unconsolidated materials. The creep behavior is modeled with a fractional power law dependence with time, which represents the Voigt material model having an extremely broad distribution of relaxation times. This analysis indicates that the characteristic relaxation times of these materials are measured in decades or longer. Creep equilibrated tests are, therefore, impractical and not relevant to a reservoir that will be depleted in one or two decades. Analysis of the power law creep parameters indicates the creep behavior is consistent at higher stresses among the materials tested. The creep parameters scale with stress and provide a means of decoupling the time-dependent behavior from the stress-strain behavior.
Type Curves for Analysis of Afterflow-Dominated Gas-Well Buildup Data
Authors: Maer N.K.
Published: December 2007

A set of type curves is described that permits estimation of near-wellbore damage or stimulation from the afterflow-dominated portion of a pressure buildup test in a gas well. The result is portion of a pressure buildup test in a gas well. The result is an improved estimate of damage or stimulation relative to that obtained with constant fluid-property analyses of afterflow-distorted data.

Introduction

The conventional semilog plot of pressure buildup data is commonly used to determine formation permeability and, by means of the skin factor and flow efficiency, the degree of near-wellbore damage or stimulation. However, when these data are distorted by afterflow, other methods of analysis are required to extract useful information. One such method involves the use of type curves. Several sets of type curves are available, all of which work well when applied to oil wells and, in many cases, to gas wells. However, all were derived assuming constant fluid properties. For gas wells, this may result in inaccurate values of permeability and flow efficiency, particularly at low pressures when the gas compressibility is large.

This paper presents an extension to gas wells of the "McKinley method" of type-curve analysis for afterflow-dominated data by including the effects of changing gas properties with pressure. While many approximations are involved, it will be demonstrated that, for gas wells, the new curves offer an improvement over McKinley's constant fluid-property curves. There is a penalty to be paid for this improved accuracy, however - the new types curves are more difficult to use than McKinley's. Therefore, they should be used only when (1) pressures beyond the afterflow region are not available for conventional semilog analysis, and (2) improved accuracy is desired relative to what would be obtained using the McKinley (or any constant fluid property) type curves to analyze gas-well buildup data. property) type curves to analyze gas-well buildup data. For rough estimates of damage or stimulation in gas wells, the easier-to-use McKinley curves will be shown to be adequate.

With these new curves, it should be possible to obtain from afterflow-distorted gas-well buildup data a reliable value for near-wellbore permeability, and improved estimates of formation permeability and flow efficiency. This information is valuable in selecting workover and stimulation candidates, as well as in evaluating the effectiveness of workovers, stimulation treatments, and well completions.

Development of the Type Curves Parameters Governing Afterflow Parameters Governing Afterflow When a flowing well is shut in at the surface, there will be a period of time during which appreciable flow into the wellbore will continue. This "afterflow" or "afterproduction" is a result of the wellbore storage capacity, which may be written

F = 5.615 cw V,.............................(1)

where

cw = wellbore fluid compressibility, psi

V = wellbore volume, bbl.

The constant 5.615 converts F to cu ft/psi.

JPT

P. 915
The Interpretation of Reservoir Pressure Data in the Dunbar Field (UKCS)
Authors: Bigno Yann , Baillie J. M. , Coombes T. P.
Published: December 2007

The Dunbar field consists of five hydrocarbon accumulations in Jurassic and Triassic sandstones. The existence and extent of dynamic connectivity between these reservoirs as well as lateral and vertical compartmentalization within each accumulation has always been a concern for choosing the optimum reservoir development of Dunbar. Combined with these uncertainties, the existence of downdip permeability deterioration and the near-critical nature of the reservoir fluid complicates the estimation of volumes connected to each well. The benefit of implementing secondary recovery schemes is also greatly dependent on these factors.

This paper presents the role of pressure monitoring as one of the main reservoir management tools for Dunbar and also the different forms of pressure measurements implemented to reduce the uncertainties (e.g., formation pressure tests, extended pressure tests, bottomhole pressure surveys and interference tests). Pressure monitoring, combined with geophysical and geological data [e.g., Strontium isotope residual salt analysis (SrRSA**1) and geochemistry], has played a key role in the early field development.
The Use of Potential Fields in the Search for Potential Fields in the Faroe-Shetland Area
Authors: Morgan Richard , Murphy Colm
Published: December 2007

Fundamental geological and environmental differences exist between the basins of the North Sea and the basins of the northwest European continental margin, and strategies for success in the North Sea have not necessarily transferred directly to the continental margin. As a result, exploration outcomes to date have been somewhat disappointing, with one or two notable exceptions.

Furthermore, a change in the approach to acreage evaluation places increasing levels of reliance on seismic data, specifically three-dimensional (3D) data, to tie down prospects before drilling. This approach focuses down rapidly to the prospect scale, and, although allowing detailed analysis of target structures, there is a risk of creating a gap in understanding between the geological processes observed at the basin scale and those at the prospect scale.

A strategy to bridge this gap has drawn upon the wider family of geophysical data, namely gravity and magnetic data, in conjunction with a conventional, broad, regional grid of two-dimensional (2D) seismic data. These data have been worked together to construct a basin scale framework into which 3D seismic data acquisition can be planned and the results interpreted.

At the regional scale, satellite-derived gravity coverage has enabled the removal of the effects of Tertiary seafloor spreading, allowing structures on the northwest European continental margin to be viewed in context with the geology of East Greenland. At the basin scale, basinal elements have been identified and correlated among seismic, gravity, and magnetic data. Controlling faults have been mapped, and the timing of basin formation inferred from trend and geometry, with implications for source rock distribution. At the license block scale, the segmentation of basin margins has been revealed by high spatial resolution magnetic data with implications for both trapping potential and the control of sediment supply into the basins.

The fusion of interpretations made from the different types of geophysical data creates a scale of observation range that stretches from tectonic plates to prospective structures. The resulting geological framework has sufficient scale overlap to relate immediately to the level of detail available from 3D seismic data. Moreover, the broader perspective may ensure that those seismic data are acquired in the correct part of the basin in the first place.
Falcon: A Production Quality Distributed Memory Reservoir Simulator
Authors: Shiralkar G. S. , Stephenson R. E. , Joubert Wayne , Lubeck Olaf , van Bloemen Waanders Bart
Published: December 2007

We describe a new production model, Falcon, that has achieved speeds on parallel computers that are 100 times faster on real world problems than current production models on a vector computer. Falcon has been used to conduct the largest, geostatistical reservoir study ever conducted within Amoco. In this paper we discuss the following: Falcon's data parallel paradigm with FORTRAN 90 and high performance FORTRAN (HPF); its single program, multiple data (SPMD) paradigm with message passing; efficient memory management that enables simulation of enormous studies; a numerical formulation that reconciles the generalized compositional approach (based on component masses and pressure) with earlier approaches (based on pressures and saturations), in a more general and more efficient approach. We also discuss Falcon's scalability up to 512 processor nodes and performance (timings and memory) achieved on a number of parallel platforms, including Cray Research's T3D and T3E, SGI's Power Challenge and Origin 2000, Thinking Machines' CM5, and IBM's SP2. Falcon also runs on single processor computers such as PC's and IBM's RS6000. We discuss a new parallel linear solver technology based on a fully parallel scalable implementation of incomplete lower-upper (ILU) preconditioning coupled with a GMRES or Orthomin iteration process. This naturally ordered global ILU preconditioner is scalable to hundreds of processors, efficiently solving the matrix problems arising from large scale simulations

The use of the techniques described in this paper has enabled us to run problem sizes of up to 16.5 million gridblocks. Falcon was used to simulate fifty geostatistically derived realizations of a large, black oil waterflood system. The realizations, each with 2.3 million cells and 1,039 wells, took an average of 4.2 hours to execute on a 128-node CM5 computer, thus enabling the simulation study to finish in less than a month. In this field study, we bypassed upscaling through the use of fine vertical resolution gridding.

Our focus has been on the applicability of Falcon to real world problems. Falcon can be used for modeling both small and very large reservoirs, including reservoirs characterized by geostatistics. It can be used to simulate black oil, gas/water, and dry gas reservoirs. And, a fully compositional feature is being developed.
Linearization Techniques of Reservoir-Simulation Equations: Fully Implicit Cases
Authors: Farkas Éva
Published: December 2007

The complexity and nonlinearity of reservoir simulation equations make it possible to apply a great number of linearization techniques. The SPE comparison projects and some other papers compare models for various problem classes. These papers generally compare the results and the speed of runs. The main object of this paper is to examine and compare the models on the basis of the numerical background of the linearization techniques. A general comparison method is proposed that can be applied to analyze these techniques.

Recently, the proposed comparison method has been applied to examine implicit pressure, explicit saturations (IMPES) and implicit pressure, explicit masses (IMPEM) techniques. It has been revealed that the direct IMPES and IMPEM methods result in exactly the same pressure distribution, whereas the saturations and the masses are different. By applying the primary set transformation techniques, the saturation and mass distributions of the direct IMPES and IMPEM techniques can be transformed from one into the other. Now, the fully implicit methods are compared for a three-phase black oil system with one-dimensional (1D) radial grids. The relationships and convergence behavior of the implicit techniques are discussed.
Field Results Demonstrate Enhanced Matrix Acidizing Through Real-Time Monitoring
Authors: Zhu Ding , Hill A. D.
Published: December 2007

The use of an inverse injectivity vs. superposition time plot to diagnose the changing skin factor in a matrix acidizing treatment has been presented previously by Hill and Zhu.1 The model has been extended to calculate skin factor as a function of injection time or injected volume to help the operator monitor and optimize the treatment. A Windows program based on the theory has been developed to provide a pretreatment test to evaluate permeability and initial skin factor of the formation when they are not available before the acid treatment, to calculate and plot the evolving skin during the treatment in real time, and to evaluate treatments afterward. It converts surface pressure, when measured, to the bottomhole pressure for the calculation, and handles fluid density and viscosity changes in real time. Several field examples showed that the technique can be used conveniently to monitor skin changes and diversion effects during matrix acidizing treatments. The program is reliable and flexible in acquiring and processing data, calculating skin, and diagnosing matrix acidizing treatments.
A Systematic Experimental Study of Acid Fracture Conductivity
Authors: Beg M. S. , Kunak A. O. , Gong Ming , Zhu Ding , Hill A. D.
Published: December 2007

The fracture conductivity created in the acid fracturing process is critical to the success of this stimulation method, but is difficult to predict. We have conducted a series of experiments in which core samples were acidized in a cell that allows for linear flow through a vertical fracture with fluid loss through the cores. The fracture conductivity created was then measured as a function of closure stress. We find that increased acid contact time sometimes results in lower fracture conductivity, fluid loss can increase fracture conductivity, and the Nierode-Kruk correlation1 accurately predicts the effects of rock embedment strength and closure stress on acid fracture conductivity. We also observed that high fracture conductivity is created when the acid forms a deep channel in the fracture.
Making Sense of Water Injection Fractures in the Dan Field
Authors: Ovens J. E. V. , Larsen F. P. , Cowie D. R.
Published: December 2007

Water injection above fracture propagation pressure is used to provide improved recovery in the Dan field, a low permeability chalk oil field located offshore Denmark.

Several monitoring techniques have been applied to evaluate fracture height, length, orientation, and injector/producer interaction, including: openhole and through casing saturation logging, tracer injection, producer water cut monitoring, and falloff surveys in injection wells. This paper presents the different monitoring techniques, the development of a fracture growth model, and various examples of the way the model has been used to enhance the understanding of field data.
Modeling of Pressure Buildup on a Kicking Well and Its Practical Application
Authors: Miska S. Z. , Samuel G. R. , Azar J. J.
Published: December 2007

We describe a new method for prediction of pore pressure and formation permeability from a kicking well. Getting reliable and accurate information about reservoir parameters (when the formation damage is minimal) is of importance for making proper well completion decisions. In addition, when a well kicks, inaccurate estimation of the formation pressure may cause loss of equipment, possibly the well, and human lives. To combat these problems, a conventional pressure analysis method is modified to predict the formation pore pressure and estimate horizontal and vertical formation permeabilities from a kicking well. The method is simple, and the only prerequisite is that the buildup data be collected upon shutting in a kicking well. Examples with simulated and actual field data are provided to demonstrate the practical application of the method.
Criteria for Backproduction of Drilling Fluids Through Sand-Control Screens
Authors: Marken C. D. , Markestad Per , Rørvik O. H.
Published: December 2007

By setting sand-control screens for openhole completions in the same fluid that is used for drilling into the reservoir, considerable cost savings can be realized through the elimination of the need for displacing to a specialized completion fluid. The control of the particle composition of fluids is beneficial in preventing the plugging of the sand-control screens. Conditioning the fluid with fine grade shaker screens for removing the larger fluid particles is sufficient to decrease the amount of screen plugging when back-producing the drilling fluid in the annulus between the screen and formation. Fluids with a lower solids loading are also beneficial for reducing screen plugging. In comparison with direct laboratory evaluations of the screens, particle-size distribution measurements have been found to be insufficient at predicting sand screen plugging.
Planning the First Deepwater Well Offshore Norway
Authors: Minton R. C. , Thorogood J. L.
Published: December 2007

BP Norge was awarded acreage in the Norwegian Fifteenth Licensing Round, with water depths up to 1420 meters. Three-dimensional seismic studies revealed a number of significant structures in these licenses, and the decision was made to evaluate the most interesting of these at the earliest opportunity. As a consequence, the well engineering team proceeded to plan the first exploration well, which was to be drilled in 1275 meters of water in the Nyk High area off northern Norway.

The team faced two significant challenges. The rig market for fourth generation semisubmersible drilling units capable of drilling in these water depths was such that there were no Norwegian approved vessels available. Hence, they had to plan for the importation of an appropriate rig and introduce a new drilling contractor to the Norwegian sector. Additionally, the water depth was indicative of a dynamically positioned drilling operation, and the Norwegian authorities needed to be convinced that this unit and the associated drilling program were appropriate for the task at hand.

Consequently, there were a number of key processes that were central to the success of this exercise. These included detailed project planning, wide ranging risk assessments, and accessing the knowledge and skills of groups inside BP Exploration with experience in these operations. Visible compliance with our internal technical and Health, Safety, and Environment (HSE) systems and policies was a central feature of this project, along with compliance with the Norwegian requirements. As the first well of this nature in the Norwegian sector, these processes were all key to final approval to proceed with the drilling activity.

We describe how these aims were achieved by detailing the well engineering team project management, the risk assessment procedures that were implemented, the approach to regulatory compliance, and the verification processes that were put in place. The detailed engineering studies and the performance of the first well will be reported separately in later papers.
Gulf of Mexico Subsidence Monitoring Project With a New Formation-Compaction Monitoring Tool
Authors: de Kock A. J. , Johnson T. J. , Hagiwara Teruhiko , Zea H. A. , Santa Fernando
Published: December 2007

Formation compaction in unconsolidated geopressured turbidite reservoirs in the Gulf of Mexico (GOM) is an issue of great uncertainty and concern. When compaction occurs, it changes the porosity and permeability properties of the reservoir rock and can affect recovery efficiency and well productivity. It can deform well tubulars, creating operational problems and shortening well life. If compaction is significant, especially when multiple stacked reservoirs are involved (as in the case in this field example), then compaction can create a subsidence bowl at the ocean floor. In GOM offshore operations, this could cause platforms to subside deeper into the water and create potentially severe safety problems; therefore, failure to properly address issues of compaction and subsequent subsidence during the design and development phases of these capital intensive, deepwater projects could lead to severe financial setbacks.

It is crucial to have a compaction monitoring program in place because of the broad impact of compaction and seafloor subsidence. As a result, we developed a new formation-compaction monitoring tool (FCMT) and new methods of measurement and interpretation. The FCMT is a wireline device that uses multiple gamma ray detectors to determine locations of and precise distance between radioactive (RA) markers planted in the formation or casing. Compaction of the formation can be measured by changes in the distance between the markers. For precise estimation of the vertical distance between a pair of markers, the new method uses an array of three or four detectors.

By examining the tool response to a marker, we developed a new method to determine the exact vertical and lateral location of the marker by using a Lorentzian response model; consequently, not only the vertical compaction but also lateral displacement of markers can be monitored with the new method.

The accuracy of the tool was established in the test facility where gamma ray sources were placed at precisely known intervals. The tools were run centralized at three logging speeds (5, 10, and 15 ft/min.), and data were collected at 0.1-in. intervals. The vertical distances between a pair of RA markers spaced 30 ft apart were measured accurately to within 0.1 in.

The first baseline logs were collected successfully in the four wells in a GOM deepwater development. High consistency among measurements from different logging passes proved that the FCMT can provide precise distance measurements with newly developed methods.