bluuebunny/crossref_metadata_2025 huggingface dataset:
Efficient Conditioning of 3D Fine-Scale Reservoir Model To Multiphase Production Data Using Streamline-Based Coarse-Scale Inversion and Geostatistical Downscaling
Authors: Tran Thomas T. , Wen Xian-Huan , Behrens Ronald A.
Published: December 2007

In addition to seismic and well constraints, production data must be integrated into geostatistical reservoir models for reliable reservoir performance predictions. An iterative inversion algorithm is required for such integration and is usually computationally intensive because forward flow simulation must be performed at each iteration. This paper presents an efficient approach for generating fine-scale 3D reservoir models that are conditioned to multiphase production data by combining a recently developed streamline-based inversion technique with a geostatistical downscaling algorithm.

Production data cannot reveal fine-scale details of reservoir heterogeneity because they respond to the spatial variation of larger-scale effective properties. By solving the streamline pressure solution at a coarse scale consistent with the volume support of production data, we are able to invert numerous geostatistical realizations. Additionally, the streamline method allows fine resolution along the 1D streamlines independent of the coarse-grid pressure solution, so we do not need to explicitly address multiphase scaleup.

Multiple geostatistical fine-scale models are upscaled to a coarse scale used in the inversion process. After inversion, the models are each geostatistically downscaled to multiple fine-scale realizations. These fine-scale models are now preconditioned to the production data and can be upscaled to any scale for final flow simulation.

A 3D extension of the prior 2D sequential self-calibration method (SSC) is developed for the inversion step. This method updates the coarse models to match production data while preserving as much of geostatistical constraint as possible. A new geostatistical algorithm is developed for the downscaling step. We use Sequential Gaussian Simulation (SGS) with either block kriging or Bayesian updating to "downscale" the history-matched coarse scale models to fine-scale models honoring fine-scale spatial statistics. Combining these two developments we are able to efficiently generate multiple fine-scale geostatistical models constrained to well and production data.
History Matching Under Training-Image-Based Geological Model Constraints
Authors: Caers Jef
Published: December 2007

History matching forms an integral part of the reservoir modeling workflow process. Despite the existence of many history-matching tools, the integration of production data with seismic and geological continuity data remains a challenge. Geostatistical tools now are routinely employed for integrating large-scale seismic and fine-scale well/core data. A general framework for integrating production data with diverse types of geological/structural data is largely lacking. In this paper, we develop a new method for history matching that can account for production data constraint by prior geological data, such as the presence of channels, fractures, or shale lenses. With multiple-point (MP) geostatistics, prior information about geological patterns is carried by training images from which geological structures are borrowed, then anchored to the subsurface data. A simple Markov chain is proposed to iteratively modify the MP geostatistical realizations until history match. The method is simple and general in the sense that the procedure can be applied to a wide variety of geological environments without requiring a modification of the algorithm. The method does not make assumptions on the flow model. Synthetic cases are used to assess the flexibility of the proposed method.
Application and Analysis of Simultaneous Near Bit and Surface Dynamics Measurements
Authors: Macpherson J. D. , Jogi P. N. , Kingman J. E. E.
Published: December 2007

Axial, torsional, and bending vibrations are all present in a bottomhole assembly (BHA) while drilling. The dynamic response of the BHA depends on many variables, such as drilling parameters, BHA design, hole condition and inclination, and formation properties. Events, such as bit bounce, forward and backward whirl of the BHA and the bit, and drillstring resonance can occur during drilling. Some of these events are very detrimental and can cause drillstring component failures, twist-offs, etc.

This paper deals with the analysis of measured drilling vibration data from a field test that used both downhole- and surfacevibration measurement devices. Surface sensors included dynamic axial and torsional strain gauges and accelerometers and a singleaxis magnetometer, all mounted in the drillstring above the rotary table. Downhole sensors included an axial accelerometer, two orthogonal bending-moment strain gauges, dynamic weight-on-bit (WOB) and torque strain gauges, and two orthogonal magnetometers, mounted in a measurement while drilling (MWD) sub. The field test involved several drilling runs that included drilling and reaming with polycrystalline diamond compact (PDC) and tricone bits in rotary and motor assemblies.

The analysis described in this paper involves the determination of axial and torsional wave velocities in the drillstring; their use in predicting resonant frequencies; a comparison of predicted and measured resonant frequencies; inference of downhole dynamics with surface measurements (surface noise cancellation), including a comparison of results with measured downhole data; an example of the detection of BHA whirl with downhole data; an example of the detection of bit bounce with downhole axial data; and an examination of precession of the trilobed bottomhole pattern generated by a tricone bit.

The advantages of using either surface or downhole dynamic measurements in identifying different drilling problems are demonstrated as well as the inference of downhole dynamics with surface measurements. Once drilling dynamics problems are identified, remedial action can be taken to reduce tool and bit failures while drilling, thus optimizing the drilling process.
Pressure Transient Analysis for Two-Phase (Water/Steam) Geothermal Reservoirs
Authors: Garg S. K.
Published: December 2007

A new diffusivity equation for two-phase (water/steam) flow in geothermal reservoirs is derived. The geothermal reservoir may be initially two-phase or may evolve into a two-phase system during production. Solutions of the diffusivity equation for a continuous line source are presented; the solutions imply that the plot of bottomhole pressure vs. log10t (t = time) should be a straight line. The slope of the straight line is inversely proportional to the total kinematic mobility. Comparison of the theory with a limited number of computer-simulated drawdown histories shows excellent agreement.
Laboratory Studies of Gasification Kinetics for Western Coals Under Conditions Expected During In-Situ Combustion
Authors: Young John E. , Fischer Jack , Wong Samuel H.
Published: December 2007

Kinetics for the reaction of steam with western U.S. sub-bituminous chars are described for operating conditions characteristic of those expected during underground coal gasification (UCG). The mineral matter present in these coals has been found to have significant catalytic activity for the water/gas shift reaction. Also, the inorganic constituents of brackish waters occurring naturally in western aquifers have been found to have little effect on the gasification rates.
An Experimental and Analytical Study of Steam/Water Capillary Pressure
Authors: Li Kewen , Horne Roland N.
Published: December 2007

Significant mass transfer between the steam and water phases makes it difficult to measure steam/water capillary pressure using routine methods. Because of the difficulties, few experimental data are available. A formula was derived on the basis of the Kelvin equation to calculate steam/water capillary pressure. The waterphase temperatures and pressures measured with a steady-state flow method were used to perform the calculations. The preliminary results of both drainage and imbibition steam/water capillary pressure were obtained. It was confirmed that the lowering of vapor pressure was small, but the capillary pressure was significant for the system studied. This experimental observation is consistent with thermodynamic analysis.
The Nominal Sand-Control Screen: A Critical Evaluation of Screen Performance
Authors: Underdown D. R. , Dickerson R. C. , Vaughan W.
Published: December 2007

Over the past few years, several premium sand-control screens have been introduced into the market. The proliferation of new screens has raised questions about how to choose the proper sand-control screen for a particular formation. To address this concern, a project was initiated at ChevronTexaco Exploration Production Technology Co. (EPTC) to devise a method to evaluate sand-control screens.

As a result of this program, a method has been standardized for the evaluation of sand-control screens. The method, known as the screen efficiency (SE) test, shows the relationship between normalized sand-control characteristics (i.e., sand-control factor) of the screens and the normalized length of time it takes a screen to plug under a certain set of conditions (i.e., the performance factor). The results of SE tests to evaluate several sand-control screens for a North Sea and a west Africa field are discussed in the paper.

The data in this paper also document that the numerical ratings given by the manufacturers are generally not very useful in understanding the sand-control rating of the particular screen or in comparing screens from different manufacturers. In addition, the effect of particle size distribution and sand concentration on the relative performance of sand-control screens was demonstrated by a comparison of SE plots of sands from the North Sea and west Africa fields.
A Unique Cost-Effective Technique for One-Trip Selective Gravel Packing Over Multiple Zones: Dacion Field Case Study
Authors: Marshall John , Obianwu Chike , Tibbles Raymond , Vargas William
Published: December 2007

Selective gravel-pack completions of multiple zones present the oil industry with major challenges and expenses. Current practices have two key problems associated with them: they are limited to zones separated by 30 to 50 ft (depending on the treatment type) because of the length of the assemblies, and they have proven to have a higher risk of installation failure.

This paper describes equipment and procedures for gravel packing multiple zones in a single completion with total zonal isolation for spacing as small as 5 ft. Zones can be produced separately or comingled. Risk of execution failure is significantly lower than with conventional stacked packs. Production data is presented that verifies complete zonal isolation, improved productivity, and reduced costs from this technique.
Wellbore Position Errors Caused by Drilling-Fluid Contamination
Authors: Wilson Harry , Brooks Andrew G.
Published: December 2007

Recent improvements in magnetic-survey quality control have revealed the presence of systematic azimuth anomalies that affect the calculated trajectories of a significant number of wells. Although these anomalies display some features commonly associated with drillstring magnetic interference, they cannot be removed by traditional magnetic correction techniques. New magnetic-survey quality-control procedures have identified the problem as an attenuation of the transverse component of the Earth's field, similar to that caused by magnetically permeable material surrounding the magnetometers. The drill collars housing the sensors were inspected but showed no magnetic susceptibility, which led to the suspicion that the problems were caused by magnetic particles suspended in the drilling fluids. Laboratory testing has confirmed the magnetic properties of these fluids, and chemical analysis has verified the presence of iron in significant quantities. Field examples demonstrate the use of a multiple-survey qualitycontrol and correction method for identification and removal of these survey anomalies.
Diagnostic Techniques To Understand Hydraulic Fracturing: What? Why? and How?
Authors: Cipolla C. L. , Wright C. A.
Published: December 2007

In recent years, there have been numerous advances in fracture mapping/diagnostic technologies. This paper details the state of the art technologies in applying both conventional and advanced methods to better understand hydraulic fracturing and improve treatment designs. The initial portion of the paper describes the application and limitations of various diagnostic tools and methods, including well testing, net pressure analysis (fracture modeling), techniques that employ open-and cased-hole logs, surface-and downhole-tilt fracture mapping, microseismic fracture mapping, and production-data analysis. The bulk of the paper is dedicated to case histories that illustrate the application of these fracture-diagnostic technologies. The case histories include examples of how several fracture diagnostics can be used in concert to provide more reliable estimates of fracture dimensions and allow better economic decisions.
Selective Plugging of Waterflood Input Wells Theory, Methods and Results
Authors: Breston Joseph N.
Published: December 2007

Selective plugging is a practical and economical method for preventing the wasteful circulation of water through barren zones and fractures. It is accomplished by injection into the wellhead of finely divided in a suitable liquid carrying agent, either oil or water.

The paper describes several plugging agents now in use and the methods of application for such typical problems as open sand streaks natural and induced fractures, leaky packers or casing settings and thief zones.

Field results are given for several typical selective plugging operational in Pennsylvania, Illinois, Oklahoma and Texas. These show how selective plugging reduced the amount of water injected and increased oil production.

Introduction

In most oil reservoirs the oil saturated formations have strata of varying permeabilities. In the process of water flooding the more permeable strata are depleted of oil first, and thereafter they continue to take large quantities of water even though they produce no more oil. Under such conditions the following will result:Large quantities of water are circulated through depleted formations making unnecessary expense in the way of water costs and pumping.The injection rate (pressure) may have to be reduced resulting in insufficient pressure on the less permeable strata causing the oil in them to be unrecoverable.High back-pressure in the vicinity of the producing well which will interfere with the flow of oil from the less permeable strata.

Formation fractures natural or induced, will also by-pass large quantities of water. In fact, they are often the reason for failure of a flood right from the start. By-passing of water through fractures creates the same conditions as by-passing through highly permeable strata only worse. Loss of useful water will also result from leaky packers or casing settings and thief zones.

These problem conditions were recognized soon after pressure flooding was started over a generation ago. Solutions were hoped for in the haphazard dumping in of nearly every granular solid imaginable along with portland cement, aqua gel and miscellaneous "gumbos." It wasn't until 1942, however, that a scientific approach was made to the problem through research sponsored by the Pennsylvania oil operators at the Pennsylvania State University. By 1944 the theory of selective plugging was well advanced and a practical plugging agent developed for the Bradford Third sand. Since then selective plugging agents and methods have been developed for conditions in most waterflooding areas of the country.
Bank Financing of Secondary Recovery Projects
Authors: Brown C.L.
Published: December 2007

Normally, much of the investment requirements of the average independent oil operator desiring to develop a secondary recovery project will be sought from a lending institution. The criteria by which The Chase Manhattan Bank judges such an application are discussed detail. To satisfy itself that the undertaking is one which it may be proper to finance, the bank considers managerial competence of the operator, the engineering information and program, and an economic analysis of the project and proposed financing.

The application of these principles to the case of a successful water flood in the Mid-Continent area is presented to illustrate the importance of the bank's standards in considering the financing of a secondary recovery project.

Good management and competent, continuing engineering guidance are considered essential to a financeable secondary recovery project. The quality of the properties must be proven by comparison of laboratory data and engineering studies with pilot flood performance. The amount of financing the bank will be willing to undertake is determined by an economic analysis and valuation method described in the paper.

Introduction

During the next 10 years, according to recent predictions, petroleum production in the United States will fail by over 10 billion bbl to meet domestic demand. A recent study forecasts domestic crude oil requirements of 9,155,000 B/D during 1957, rising to 13,375,000 B/D in 1966, which will total approximately 40.63 billion bbl for the decade. Predicted production rates in the United States range from 7,600,000 B/D in 197 to 9,250,000 B/D in 1966, amounting to only 30.44 billion bbl.

That the industry has assigned a major role to secondary recovery in meeting the future deficiency is apparent from recent reports. Several researchers have been working on in situ combustion and at least one field test of this method is now in progress. Bottom-hole heaters have been tested and the use of hot-injection water has been advocated for water flooding. There is current interest expressed in the use of light hydrocarbon fractions for the displacing fluid. The use of carbon dioxide and of wetting agents in injection water has been the subject of many excellent articles on net waterflood techniques. These are only a few examples of the intense interest manifested in secondary recovery.
Measurement of Dynamic Proppant Fall Rates in Fracturing Gels Using a Concentric Cylinder Tester (includes associated paper 9970 )
Authors: Hannah Robert R. , Harrington Larry J.
Published: December 2007

This paper describes the measurement of proppant terminal velocity in a simple non-Newtonian gel during shear. The shear was imposed between Lucite™cylinders with the outer cylinder rotating. During rotation, a proppant particle was introduced and the terminal velocity was measured. This measurement then was compared with Stokes law measurement then was compared with Stokes law using the fluid's apparent viscosity at the known shear rate for the Newtonian viscosity. This results in a good correlation between measured and theoretical data.

Introduction

Most of the early work done on sand settling used vertical fracturing models. Kern et al.1 and Babcock et al.2 reported on tests performed in such models which defined equilibrium bank height and equilibrium velocities. Novotny3also used a vertical model in his proppant transport study. Wahl4 studied the transport of proppants in a horizontal model.

A knowledge of particle settling velocity is a necessary input in all design techniques that describe the final location of proppants in the fracture. For Newtonian fluids, the measurement of settling velocity is straightforward since their viscosity remains constant with variations in shear rate. For these fluids, particle settling velocity will follow Stokes law for particle Reynolds numbers less than two. For all but very thin fracturing fluids, particle Reynolds numbers will be in this range. Under these conditions, single particle settling velocity will follow Stokes law:Equation 1

This is the settling velocity for a single particle in an infinite media.

Most fracturing gels, on the other hand, are non-Newtonian in character and are considered to follow the power law:Equation 2

Under these conditions, Stokes law becomesEquation 3

From this equation, settling velocity becomes a function of shear rate. As shown by Novotny,3 shear rate (?) consists of two components: a horizontal component imposed by fluid motion and a vertical component imposed by particle settling. The vertical shear rate can be expressed by V/d, and the combined shear rate becomesEquation 4

This shear rate expression leads to an altered form of Eq. 3. For the fluids used in these tests, the vertical shear rate V/d is very small and can be ignored without significant error.

The experiments conducted were designed to see how closely dynamic particle fall velocity would follow Stokes law for the shear rate range imposed by the test device. If the measured values agreed with Stokes law, only a knowledge of shear rate would be required to predict settling velocity. Novotny3 found a good correlation working with a similar tester. The fluids used in our test were somewhat more viscous than shown by Novotny.3
Effect of Fractional Flow Hysteresis on Recovery of Tertiary Oil
Authors: Gladfelter Robert E. , Gupta Surendra P.
Published: December 2007

This paper deals with the oil/water bank propagation in a tertiary oil recovery process. Oil/water bank propagation was studied in a series of laboratory micellar floods and simultaneous oil/water flow tests using a microwave scanning apparatus for measuring in-situ dynamic oil saturation. It was observed that a high oil saturation region, or hump, developed at the leading edge of the oil/water bank and grew linearly with distance. A lower steady-state oil saturation region was observed behind the hump. As the hump was produced from the core, high initial oil fractions were observed, as often seen in laboratory micellar floods. This is the result of the observed hysteresis in fractional flow behavior.

A graphical method of predicting the occurrence of a hump, its rate of growth, and saturations within an oil/water bank was developed using the observed hysteresis in fractional flow. Using this prediction procedure, it was concluded that in a tertiary oil recovery process, oil breakthrough time or rate of advance of the oil/water bank, oil saturation at the leading edge, and initial produced oil fractions are only functions of the oil-saturation-increasing fractional flow curve and are not necessarily indications of oil recovery efficiency.
Effect of Dispersion on Local Displacement Efficiency for Multicomponent Enriched-Gas Floods Above the Minimum Miscibility Enrichment
Authors: Johns R. T. , Sah P. , Solano R.
Published: December 2007

Recent research on four-component 1D displacements has shown that enriching the gas above the minimum miscibility enrichment (MME) can increase oil recovery substantially for certain systems. Research has shown further that the oil-recovery increase can be very sensitive to the level of dispersion at the enrichment chosen.

The main focus of this paper is to extend the research on four-component systems to displacements of multicomponent oils and gases in which the recovery is affected by dispersion and enrichment. We consider here a 12-component oil displaced by solvents enriched above the MME. For this case, the increase in recovery (displacement efficiency) above the MME can be as large as 15% original oil in place (OOIP), depending on the level of mixing. The methodology outlined can be used as a screening tool to determine whether a significant benefit may exist and whether further 2D and 3D studies are warranted.

A secondary focus of the paper is to examine in detail how dispersion affects recoveries and displacement mechanisms for the 4- and 12-component systems. We show that for the case of the four-component model, the displacement mechanism changes from a combined condensing/vaporizing (CV) displacement to a strictly condensing one as enrichment increases above the MME. We also show how to quantify the percentage of the CV displacement that is vaporizing or condensing by calculating the compositional distances between key tie lines identified from "dispersion-free" theory.
Potential New Sources of Natural Gas
Authors: Schrider Leo A. , Wise Robert L.
Published: December 2007

The U.S. DOE's gas resource program aims at resolving existing technological barriers to effective recovery of natural gas from Devonian shale and methane from coalbeds. Upon completion of these projects, DOE expects the technology developed jointly with industry to result in wide-scale recovery and use of these new sources of natural gas.

Introduction

Natural gas continues to be one of the major sources of energy produced and used in the U.S. Declining gas reserves and curtailment of supplies have reemphasized the major influence this energy source has on the U.S. economy. The U.S. DOE is investigating several options for increasing the supply, including a program for unconventional gas recovery (UGR). Four UGR projects currently are being assessed: western tight gas sands, geopressured reservoirs, Devonian shales, and methane from coalbeds. Both the Devonian shale and methane from-coalbeds projects are paramount in this assessment, since they underlie a large section of the U.S. The eastern (Devonian) shales contain a vast, essentially unexplored volume of natural gas. This area could represent new gas recovery from approximately 250,000 sq miles throughout the U.S. Studies by the government and industry have been focused on shale characterization to determine the magnitude of potential gas reserves and technology development needed to improve current state-of the-art stimulation techniques. The initial R and D results have shown promise and point out the technology needed for successful development. The goal of the methane-from-coalbeds project is to provide natural gas from coal seams. While coal itself is recognized as a major energy source, it also contains vast quantities of methane gas. This methane source is not new, since coal mine operators have been aware of its presence and release into the atmosphere during mining operations. Technology studies are being conducted to learn the production potential of this methane and to show how this gas potential of this methane and to show how this gas may be put to widespread use.

Devonian Shales

The Devonian shales of the Appalachian, Michigan, and Illinois basins have produced natural gas since the 1800's. These shales in the eastern U.S. (Fig. 1) contain a high volume of gas. Independent estimates of the recoverable gas range from 3 Tcf to several hundred times that amount. To date, the gas produced from these shales has been limited to an produced from these shales has been limited to an estimated 2.5 Tcf because of the unpredictable behavior and economics shown by existing Devonian shale wells. Similarly, these uncertainties have restricted private-sector R and D funding and development of technology needed for Devonian shale gas production.

JPT

P. 703
Casing Drilling: An Emerging Technology
Authors: Shepard S. F. , Reiley R. H. , Warren T. M.
Published: December 2007

BP America Production Co. used the Tesco Casing Drilling™* process to drill the surface and production intervals of 15 Wyoming gas wells. These wells range in depth from 8,300 to 9,600 ft. This paper provides a case-history discussion of the critical issues encountered and resolved during the planning and operations phases of this project.

Oilfield casing was used as the drillstring, along with a wireline-retrievable bottomhole assembly (BHA), to reduce the overall time required to drill, run casing, and cement the surface holes. Drilling with casing matched the rate of penetration (ROP) for conventional wells, and both the downhole and surface tools proved to be reliable.

The production-hole interval turned out to be more challenging. Drillstring vibrations were encountered when drilling with the 4½-in. casing, and difficulty was experienced in maintaining a competitive ROP with the wireline-retrievable drilling assembly. The last 11 production holes were drilled with casing and a nonretrievable bit assembly. Nine of these wells were completed without tripping the casing. Drilling times were competitive with conventional drilling in the Wamsutter area. One of the wells was the third-fastest well ever drilled in the field.

The project demonstrated that the casing-drilling process can be used successfully but may not be cost-effective in all situations. It is probably better suited to softer formations and larger casing sizes than those used at Wamsutter. The process seemed to improve wellbore stability, reduce lost circulation, and minimize gas influx, even when drilling with a lower mud weight than is typical for conventional drilling.
Integrated Study of a Fractured Middle East Reservoir With Stratiform Super-K Intervals–Part 2:Upscaling and Dual-Media Simulation
Authors: Cosentino L. , Coury Y. , Daniel J. M. , Manceau E. , Ravenne C. , Lingen P. Van , Cole J. , Sengul M.
Published: December 2007

The paper describes the upscaling and reservoir simulation of a giant Middle East oil field, the geological modeling of which is described in a companion paper.1 The main objective of the study was the simulation of the irregular water advance observed in some parts of the field as a consequence of peripheral water injection.

Three scales of heterogeneity were identified in the characterization phase: the matrix, the stratiform Super-K intervals, and the fractures. To accommodate the different hydraulic properties of each heterogeneity system, a dual-media approach (dual porosity and dual permeability) was used.

The assignment of the effective properties to the simulation grids (matrix and fracture grids) was performed independently for the three heterogeneity systems. In particular, the geostatistical facies model was upscaled with algebraic methods, while the stratiform Super-K layers and fracture properties were reproduced explicitly at the simulation gridblock scale through an original upscaling procedure.

The history match was achieved in a short time by a small variation of the fractal dimension of the fracture distribution and without resorting to any local modification.

Simulation results showed that the fracture system was the controlling factor in terms of water advance and breakthrough, while the impact of the stratiform Super-K layers proved to be of second order.

In a later stage, the model was used to run production forecasts under different exploitation scenarios.

The conclusions of this study indicate that for such porous and fractured reservoirs with stratiform Super-K occurrences, a detailed characterization of all the heterogeneity systems, coupled with a dual-media formulation, is necessary for accurate reservoir simulation and effective reservoir management.
Use of Carbon/Oxygen Logs Run in Open Hole in Wells Drilled With Oil-Based Muds
Authors: Sullivan M. J. , Belanger D. L. , Stewart W. F.
Published: December 2007

Carbon/oxygen (C/O) logs have been run in open hole to assess zones that are potentially swept with fresh injection water in several infill wells offshore Cabinda, Angola.

Interpretation of these logs has been challenging because of the invasion of oil-based mud (OBM) filtrate, mixed sand/carbonate lithology, variable water salinity, large boreholes, and lack of clean wet zones in which to normalize. We discuss the impact of these factors and our experiences in managing them. An example is included in which the results of time-lapse logging suggest that the invasion of OBM filtrate in water zones dissipates slowly or not at all. We show comparisons between saturations derived from the resistivity and the C/O ratio (COR) for these various conditions.
Performance of Linear Algebra Codes on the CRAY-1
Authors: Calahan Donald A.
Published: December 2007

As of 1978, the CRAY-1 has potentially the highest floating-point computation rate in both scalar and vector modes of any available general scientific processor. Exploitation of this superior capability is the subject of this paper. In particular, we consider (1) mathematical models, software issues, and performance measures of vector machines, (2) algorithmic and coding procedures related to development of linear algebra codes on the CRAY-1, and (3) performance of direct solution codes commonly encountered in reservoir simulation.
Perforating for Stimulation: An Engineered Solution
Authors: Lestz R. S. , Clarke J. N. , Plattner D. , Byrd A. C.
Published: December 2007

Point-source perforating has reduced fracture-stimulation expenses in the south Texas Lobo trend. Although the producing intervals frequently exceed 100 ft, the operator typically perforates the bottom 5 ft of the interval. Data collected during perforating are used to design optimized fracture-stimulation treatments. The optimized treatments average 55% less proppant than the jobs designed previously with conventional practices that had perforations across the entire pay interval. The new well's initial production and sustained performance has been higher than conventionally stimulated wells of similar potential. In addition, the point-source-perforated wells have produced significantly less proppant than similar wells with perforations across the entire pay interval. Point-source perforating has reduced the cost of perforating, proppant, fluids, equipment rentals, and cleanup.

This case-history paper presents the following.

Historical account of previous completion practices (limitedentry, multiple-stage fracturing, and full-zone perforating). Discussion of the "perforating for stimulation" fracturingtechnique currently used. Comparison of production results. Formation-evaluation methods (logs and bottomhole gauges). Perforating methods (phasing, charges, and perforating-interval selection). Results from a recompletion confirming that depletionhas occurred.
Evaluation of a pH-Sensitive Polymer for Gravel-Packing Operations
Authors: Al-Anazi Hamoud A. , Sharma Mukul M.
Published: December 2007

Rheological data is presented for a type of polyacrylic acid polymer as a function of polymer concentration, pH, shear rate, and temperature. It was found that the viscosity of the polymer is strongly dependent on the pH of the solution. Compatibility tests showed that the polymer was compatible with most brines (NaCl, NH4Cl, and KCl) used for field applications. Core-flow results indicated that the filtration rate was low compared to that of hydroxethylcellusose (HEC). Our evaluation study shows that this anionic polymer would be an excellent nondamaging carrier fluid for gravel packing. It has excellent rheological and suspension properties and is easily broken down with a mild acid wash before flowback.
An Improved Formulation and Solution Method for Single-Phase Flow Problems
Authors: Welty Douglas H. , Meijerink J. A.
Published: December 2007

This paper presents an improved formulation and solution method for use in single-phase finite difference reservoir simulators. The formulation allows easy, implicit inclusion of source and sink terms (wells) in the solution. The equations are expressed in residual form, and a Newton-Raphson scheme is used to update any nonlinearities in both the well model and fluid properties.

The resulting system of linear algebraic equations is solved using the symmetric strongly implicit procedure (SSIP). SSIP is an iterative solution algorithm that is highly efficient with respect to both work and storage requirements. Additionally, SSIP is not very sensitive to high transmissibility ratios in the reservoir description. Our experience indicates that this combination of formulation and solution methods is reliable and efficient.
Coiled-Tubing Drilling: Continued Performance Improvement in Alaska
Authors: McCarty Thomas M. , Stanley Mark J. , Gantt Lamar L.
Published: December 2007

Coiled-tubing drilling (CTD) has thrived in recent years on the North Slope of Alaska. To date, CTD has sidetracked more than 250 wells in a continuous program of activity since 1995. In that time, Alaska has become a proving ground for CTD tools and techniques. CTD has matured into a highly efficient and economical means of sidetracking wells on the North Slope. Key reasons for the success of the program include continuous use, which allows rapid learning; a culture of technical innovation; effective performance-based service contracts; the right people with the right expertise; and the vision and support of senior management. This paper summarizes the performance improvements realized in North Slope CTD operations, detailing how the tools and techniques have changed.

Applying new technologies and improving existing tools are major levers of CTD progress. Major performance improvement areas include window milling, bottomhole assembly (BHA) reliability, and lost circulation. Reliability improvements in equipment and persistent innovation will continue to fuel CTD's underlying economic performance in Alaska.

Included in this paper is a discussion of the remaining problems associated with through-tubing, slim-hole drilling with CTD technology. Examples of new CTD technologies being used or about to be implemented in Alaska will also be presented.
Multiscale Data Integration Using Markov Random Fields
Authors: Lee Sang Heon , Malallah Adel , Datta-Gupta Akhil , Higdon David
Published: December 2007

We propose a hierarchical approach to spatial modeling based on Markov Random Fields (MRF) and multiresolution algorithms in image analysis. Unlike their geostatistical counterparts, which simultaneously specify distributions across the entire field, MRFs are based on a collection of full conditional distributions that rely on the local neighborhoods of each element. This critical focus on local specification provides several advantages: (a) MRFs are computationally tractable and are ideally suited to simulation-based computation, such as Markov Chain Monte Carlo (MCMC) methods, and (b) model extensions to account for nonstationarity, discontinuity, and varying spatial properties at various scales of resolution are easily accessible in the MRF framework. Our proposed method is computationally efficient and well suited to reconstruct fine-scale spatial fields from coarser, multiscale samples (based on seismic and production data) and sparse fine-scale conditioning data (e.g., well data). It is easy to implement, and it can account for the complex, nonlinear interactions between different scales, as well as the precision of the data at various scales, in a consistent fashion. We illustrate our method with a variety of examples that demonstrate the power and versatility of the proposed approach. Finally, a comparison with Sequential Gaussian Simulation with Block Kriging (SGSBK) indicates similar performance with less restrictive assumptions.
Simulation of Hydraulic Fracturing Processes
Authors: Settari A.
Published: December 2007

A mathematical model of the fracturing process, coupling the fracture mechanics and fracture propagation with reservoir flow and heat transfer, has been formulated. The model is applicable to fracturing treatments as well as to high leakoff applications such as fractured waterfloods and thermal fractures. The numerical technique developed is capable of simulating fracture extension for reasonably coarse grids, with truncation error being minimized for high leakoff applications when the grid next to the fracture is approximately square. With the aid of the model, a generalization of Carter's propagation formula has been developed that is also valid for high fluid-loss conditions. The capabilities of the model are illustrated by examples of heat transfer and massive-hydraulic-fracturing (MHF) treatment calculation.
Full-Field Modeling Using Streamline-Based Simulation: Four Case Studies
Authors: Baker R.O. , Kuppe F. , Chugh S. , Bora R. , Stojanovic S. , Batycky R.
Published: December 2007

Modern streamline-based reservoir simulators are able to account for actual field conditions such as 3D multiphase flow effects, reservoir heterogeneity, gravity, and changing well conditions. A streamline simulator was used to model four field cases, with approximately 400 wells and 150,000 gridblocks. History-match run times were approximately 1 CPU hour per run, with the final history matches completed in approximately 1 month per field. In all field cases, a high percentage of wells were history matched within the first two to three runs.

Streamline simulation not only enables a rapid turnaround time for studies, but it also serves as a different tool in resolving each of the studied fields' unique characteristics.

The primary reasons for faster history matching of permeability fields using 3D streamline technology as compared to conventional finite-difference (FD) techniques are as follows:

Streamlines clearly identify which producer-injector pairs communicate strongly (flow visualization). Streamlines allow the use of a very large number of wells, thereby substantially reducing the uncertainty associated with outer-boundary conditions. Streamline flow paths indicate that idealized drainage patterns do not exist in real fields. It is therefore unrealistic to extract symmetric elements out of a full field. The speed and efficiency of the method allows the solution of fine-scale and/or full-field models with hundreds of wells. The streamline simulator honors the historical total fluid injection and production volumes exactly because there are no drawdown constraints for incompressible problems. The technology allows for easy identification of regions that require modifications to achieve a history match. Streamlines provide new flow information (i.e., well connectivity, drainage volumes, and well allocation factors) that cannot be derived from conventional simulation methods.
Automatic Decline-Curve Analysis of Wells in Gas Reservoirs
Authors: Hagoort Jacques
Published: December 2007

A method is presented for automatic decline-curve analysis (DCA) of wells in gas reservoirs. It is based on the production behavior of a vertical well in a finite, plane reservoir containing dry gas. The method accounts for pressure-dependent gas properties, covers both transient and boundary-dominated flow, and can accommodate varying wellbore pressures. The physical parameters that govern the production behavior are estimated by nonlinear regression of observed-rate data. Interpretation of the transient flow period yields flow capacity (kh) and skin factor; the boundary-dominated flow period provides well index (WI) and gas initially in place (GIIP). Future production rates can be estimated for operating conditions other than those that prevailed during the historical production period. These estimates also may include upper and lower bounds for a given confidence level. The method is illustrated by a synthetic and a real-life example of a declining production well.
Cuttings-Transport Problems and Solutions in Coiled-Tubing Drilling
Authors: Leising L. J. , Walton I. C.
Published: December 2007

In spite of the many technological advances that have accompanied the growth of coiled-tubing (CT) drilling, one significant challenge remains—effective cuttings transport, particularly in deviated wells. This paper presents a summary of cuttings-transport problems and current solutions. It is shown that, in many circumstances, hole cleaning is more efficient if a low-viscosity fluid is pumped in turbulent flow rather than a high-viscosity fluid in laminar flow. Case studies are presented that illustrate both cuttings-transport problems and routine applications without cuttings-transport difficulties. The proposed hole-cleaning models are used to interpret these data and to suggest possible alternative approaches.

Two novel approaches to understanding hole cleaning are introduced. First, for laminar flow, the distance that a particle will travel (downstream) before it falls across the annulus clearance is calculated with Stokes’ law and the local viscosity while flowing. This analysis may easily be applied to optimize mud selection and wiper trips. Applying this model to high low-shear-rate-viscosity (LSRV) gels shows that they may perform well inside casing but are expected to do a poor job of hole cleaning in a narrow, openhole, horizontal annulus without rotation. Second, for turbulent flow in horizontal wells, the concept of using annular velocity (AV) as a measure of hole cleaning is shown to be insufficient. A more complete term, annular velocity/root diameter (vARD), is introduced and should be used to compare cuttings transport in turbulent flow in horizontal wells of different cross-sectional areas.
Financing the U.K. North Sea
Authors: Ross Ian W.
Published: December 2007

The amount of financing required for developing the U.K. North Sea must be found from internal and external sources. This paper examines (1) major sources and reasons why some methods are preferable to others and (2) alternatives that are available depending on the size and financial strength of the developer and the relative risks of the projects.

Introduction

Although estimates vary, it is forecast reliably that spending on North Sea exploration and production will continue at a rate of $5 billion a year through 1985, and from that date at a rate more or less depending on U.K. government policy and exploration results. To quantify the costs in a different way, this is the equivalent of $10,000/bbl of peak daily production. When we balance this cost against the 5 to 10 years taken to develop North Sea fields, it is evident that there is a long lead time before any cash flow and, hopefully, profit pass back to the project owners. project owners. These vast sums of money have been and will continue to be raised from a number of sources. I will examine in this paper the types of financing available and cite various alternatives that companies already have used to raise funds for development. In view of the differing regulatory and tax regimes in each of the Norwegian, Danish, Dutch, French, and U.K. sectors of the North Sea, I will limit my paper to the biggest in terms of current expenditure--the U.K. sector.

Financing Sources

The major sources of financing for the North Sea to date have been the internal cash flow of the license holders, export credits and "interest relief grant" financing, and bank financing. Undoubtedly, for some of the large companies, internal financing will continue to be a major source of funding, and the long-term capital markets will provide another source, probably for those same companies. In many cases, however, the bank market will be a major source of funds, and given the quantitative ability of the market and its flexibility, bank financing is likely to continue providing a substantial portion of the funds required. In fact, one may even argue that, given the increasing investment needs of the oil industry and its increasing reliance on external financing, the banking community will be called upon to provide a larger proportion of the expenditures than it has to date.

Types of Bank Financing

Bank financing can be divided into two categories, the major distinction between them being the degree to which the lender looks directly to the general credit of a company as the source of repayment. The methods can be applied equally for the development of an oil or gas field and are basically the same for a single company as for a consortium.The first category can be called "balance sheet financing" and consists of borrowings based solely on the financial strength of the borrower.

JPT

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