bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhanced Coalbed Methane Recovery Using CO2 Injection: Worldwide Resource and CO2 Sequestration Potential
Authors: Stevens Scott H. , Spector Denis , Riemer Pierce
Published: December 2007

Injection of carbon dioxide into deep coal seams has the potential to enhance coalbed methane recovery, while simultaneously sequestering a greenhouse gas. Analysis of production operations from the world's first carbon dioxide-enhanced coalbed methane (CO2-ECBM) pilot, a 4-injector/7-producer pattern in the San Juan Basin, indicates that the process is technically and economically feasible. To date, over 2 Bcf of CO2 has been sequestered with negligible breakthrough. Enhancement of gas production can be as high as 150% over conventional pressure-depletion methods. Dewatering of the reservoir is also improved. ECBM development may be profitable in the San Juan basin at wellhead gas prices above $1.75/Mcf, adding as much as 13 Tcf of additional methane resource potential within this mature basin.

The key reservoir screening criteria for successful application of CO2-ECBM include laterally continuous and permeable coal seams, concentrated seam geometry, and minimal faulting and reservoir compartmentalization. Operational practices for CO2-ECBM recovery are still being refined. Injection wells should be completed unstimulated, while production wells can be cavitated or hydraulically stimulated. CO2 injection should be continuous and concurrent with methane production to prevent lateral water encroachment. Apart from the San Juan basin, many other coal basins have significant CO2-ECBM potential. In the U.S., the Uinta and Raton basins are geologically most favorable, while additional potential exists in the Greater Green River, Appalachian and other coal basins. Coal basins in Australia, Russia, China, India, Indonesia and other countries also have large CO2-ECBM potential. When viewed from a commercial project viewpoint, the total worldwide potential for CO2-ECBM is estimated at approximately 68 Tcf, with about 7.1 billion metric tons of associated CO2 sequestration potential. If viewed purely as a non-commercial CO2 sequestration technology, the worldwide sequestration potential of deep coal seams may be 20 to 50 times greater.
Pore Pressure and Stress Gradient Prediction in Geopressured Formations, South China Sea, PRC
Authors: Wydrinski R. , Ramos G. G. , Weng X. , Payne M. L.
Published: December 2007

One of the challenges in drilling wells in South China Sea, Peoples Republic of China (PRC), is the high-temperature/ high-pressure (HTHP) environment. In HTHP, the range of safe mud-densities fall within a very narrow window between the pore pressure and formation breakdown. Planning the three wells drilled in South China Sea relied on pore pressure and fracture gradient predictions that used seismic and sonic input data for models of compaction and borehole stresses. Pressure and stress gradients can be successfully predicted by quantifying the compaction trends and burial rates of the formations, estimating variance from these trends, and then calculating formation strength and pre-drilling stresses. Abnormal pore pressures were deduced from deviations of sonic velocities from known trends based on seismic integrated travel-time data and wireline sonic data. Rock mechanical elastic properties and strength were estimated and then the equations of elasticity and strength-constrained stresses were applied to determine the onset of shear-failure and formation breakdown. The computed safe mud densities for wellbore elastic stability ranged from 16 to 18 ppg. Because of thermal gradients between the formation and circulating mud, calculated thermal-induced stresses may have drastically lowered the breakdown pressures by as much as 1,000 to 2,000 psi. Mud cooling was not advisable in this case.
Huaibei Coalbed Methane Project, Anhui Province, People's Republic of China
Authors: Derickson J. P. , Horne J. S. , Fisher R. D. , Stevens S. H.
Published: December 2007

In cooperation with China United Coalbed Methane Corporation Ltd. (CUCBM), Texaco China BV (Texaco) is evaluating the Huaibei coal basins in northern Anhui Province for coalbed methane development. Texaco's initial exploration will focus on the Sunan and Nanping synclines where Permian-age coals are known to be within optimum maturity levels. Based on recent test drilling data, gas contents of objective coal seams are also shown to be quite attractive. However, the tectonic history of the Huaibei region presents some concern about the in-situ gas saturation levels in the coals. Even though the region certainly has some challenging technical risks, the initial technical evaluation indicates a promising potential. A multi-well core and test program has been designed to quickly and efficiently evaluate specific reservoir properties prior to critical decisions for pilot testing and full-scale commercial development. Key reservoir properties to be determined include coal thickness, permeability, porosity, gas content and gas saturation levels. Reservoir model studies using a coalbed methane simulator will then be used to examine the productive potential of the area. The variability and sensitivity of these key reservoir parameters in regard to production rates is discussed along with Texaco's exploration and development strategy. The paper also discusses the operational plans and overall strategy of managing risk by utilizing a phased approach.
Drilling a World Record ERW in the South China Sea
Authors: Talkington Brian Kelly , Morgan Dennis R. , Jiang Zhang Ming
Published: December 2007

In 1996, Phillips China, Inc. (PCI) based in Shekou, People's Republic of China, was faced with the decision to either submit a development plan for the Xijiang 24-1 Field in the 15/11 Contract Area of the South China Sea or to relinquish their rights to the field. The remote location of the field and the relative small size of the reservoir made this decision difficult. Several studies conducted over a number of years on various development scenarios indicated that any type of stand alone development, such as a small platform or subsea wells, would be uneconomical. It was, therefore, concluded that the only way of developing the 24-1 was to drill an extended reach well (ERW) from PCI's Xijiang 24-3 Platform, over 8-km away. Such a well would have a world record horizontal reach.

One of the biggest concerns for the success of an ERW was whether the platform rig, which was designed for a 4573-m measured depth (MD) (3049-m true vertical depth (TVD)) development wells, could be upgraded sufficiently. Also of concern were the relatively remote location of the Xijiang operation, the lack of experience in ERW drilling in the area, the transitional step from drilling relatively shallow development wells to drilling a world record ERW, hole stability, torque and drag, directional control, logistics and weather.

This paper will describe the upgrade process performed on the drilling rig to enable it to drill and complete this record breaking well. It will include a post-well evaluation of the upgrades. In addition, it will describe the drilling and completion of the well and how PCI addressed all the concerns listed above.
Edafic and Successional Changes Generated by Drill Wastes Application in Acid-Sulfate Soils at the Upper Orinoco Delta
Authors: Vásquez P. , Urich J. , Rodríguez A. , González V. , Marcano J. , López C. , Colombo P.
Published: December 2007

Since 1995 PDVSA environmental management policies for oil exploration and production activities (E&P), have encouraged significant research in order to safely dispose of drill cuttings (DC) in previously drained and consequently acidified wetland soils from the Orinoco upper Delta, due to the exposure of their underlying pyritic (FeS2) marine clays to more oxigenated environment. These soils with pH <3.5, high exchangeable Al (>15 meq/100g.), and low saturation of exchangeable bases (Ca, Mg), are commonly colonized by Cyperaceae weeds. In a field experiment located nearby Varadero de Manamo (Monagas state), the addition and tillage of DC in concentrations ranging from 200 to 1000 m3/ha, produced total reduction of exchangeable Al, as well as pH increase in the range of 5.6 to 6.9. During two years, floristic and successional changes were evaluated. It was observed a progressive substitution of the non palatable sedge cover by useful cattle and wildlife species (Leersia hexandra, Paspalum conjugatum, Oryza rufipogon, Cassia occidentalis, Cassia tora and Axonopus sp.). Net primary productivity changes in the range of 1.7 to 4.6 times over the control plots were found. Changes in soil chemistry, leaching and foliar accumulation of heavy metals are reported. These results show that drill cuttings are a useful resource in the reclamation of wetlands with acid-sulfate soils and for the improvement of regional biological productivity and diversity.
Get Rid of Greenhouse Gases by Downhole Disposal Guidelines for Acid Gas Injection Wells
Authors: Duncan Grant J. , Hartford Catherine A.
Published: December 2007

This paper describes technical considerations and recommendations for the design and completion of acid gas injection wells. These guidelines are based on acid gas disposal well completion and operating experience in the Jedney field. Initial operating and injection well inspection results are also described.

Waste gas from natural gas sweetening plants often contains high Concentrations of carbon dioxide and hydrogen sulphide. Downhole acid gas disposal schemes minimize environmental impact by reducing the release of carbon dioxide and sulphur compounds to the atmosphere. Challenges in the design and construction of Jedney acid gas injection systems included: equipment selection for high concentrations of sour gas, understanding the phase behaviour of acid gas mixtures, use of both new and existing wellbores, accommodation for future well interventions, and safe troublefree operations.

P. 17
Wellman Unit CO2 Flood: Reservoir Pressure Reduction and Flooding the Water/Oil
Authors: Schechter David S. , Grigg Reid , Guo Boyun , Schneider Barry
Published: December 2007

CO2 injection is a proven technology. Results from two decades of reservoir and economic performance prove that CO2 can 1) be transported over large distances via pipeline 2) handled and injected easily at well-site facilities and 3) recover oil that water injection could not mobilize. This has been accomplished at cost levels which are profitable provided enough HCPV (hydrocarbon pore volume) of CO2 is injected in the reservoir and sweep and displacement efficiency are sufficient.

The most recent challenge involves optimizing efficiency of CO2 flooding, i.e. maximizing oil recovery while at the same time reducing operating expenses. A useful method to attain the goal of CO2 flood optimization is careful performance review of better performing CO2 floods. The Wellman Unit CO2 flood has a long history. This CO2 flood is one of the most successful CO2 floods documented in terms of CO2 utilization, i.e. MCF of CO2 required to recover one barrel of oil. This paper explores the role of laboratory experimentation for improvement of performance of a mature CO2 flood.

In this paper, we will review the history of the Wellman Unit CO2 flood and examine two possibilities to optimize reservoir performance:Reducing CO2 injection pressure thereby reducing the volume of purchased CO2 while at the same time maintaining miscibility (optimum displacement efficiency) andExploring the possibility of mobilizing reserves in the water-oil transition zone below the original oil-water contact.

P. 39
Managing Structural Uncertainty in a Mature Field for Optimal Well Placement
Authors: Vincent G. , Corre B. , Thore P.
Published: December 2007

This paper was prepared for presentation at the 1998 SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, 27–30 September 1998.
Identification of Geological Shapes in Reservoir Engineering by History Matching Production Data
Authors: Rahon Daniel , Edoa Paul Francis , Masmoudi Mohamed
Published: December 2007

This paper discusses a method which helps identify the geometry of geological features in an oil reservoir by history matching of production data. Following an initial study on single-phase flow and applied to well tests, the research presented here was conducted in a multi-phase flow context.

This method provides information on:- the limits of a reservoir being explored,–the position and size of faults,–the thickness and dimensions of channels.

The approach consists in matching numerical flow simulation results with production measurements. This is achieved by modifying the geometry of the geological model. The identification of geometric parameters is based on the solution of a inverse problem and boils down to minimizing an objective function integrating the production data.

The minimization algorithm is rendered very efficient by calculating the gradients of the objective function with respect to perturbations of these geometric parameters. This leads to a better characterization of the shape, the dimension and the position of sedimentary bodies.

After describing the optimization process used, several examples are presented in this article, in particular an application of the method in a two phase water-oil case. The geological model used in this study was built using an integrated reservoir characterization tool. This heterogeneous model is composed of several geological units and contains a group of main faults whose positions represent the matching parameters used in the study.

P. 139
Prediction of Sand Problems of a Horizontal Well from Sand Production Histories of Perforated Cased Wells
Authors: Morita N. , Fuh G.F.
Published: December 2007

This paper compares numerical model predictions and laboratory data on sand production and borehole stability tests. It also compares numerical model predictions and field data on sand production and borehole stability tests. These comparisons show that model predictions agree with both field and laboratory results for sand production problems; however, for borehole stability problems, the model prediction does not necessarily agree with both laboratory and field results. The laboratory results show strong size effect, and the predicted borehole failure conditions lie between those predicted with the non-linear Mohr Coulomb and the non-linear Drucker-Prager. However, the field borehole is generally more stable than the laboratory results and its failure condition is close to the value predicted by the non-linear Mohr-Coulomb constitutive theory.

Using the field calibrated model predictions, a parametric analysis was conducted on the difference of the well flowing pressure between perforated wells and horizontal openholes. The analysis shows that the well flowing pressure to induce sand production for cased wells are normally lower than that of horizontal wells. The pressure difference mainly depends on the horizontal and axial stress ratio, rock deformation and strength properties.

P. 113
Operational Design Considerations for Frac-and-Pack Tools to Reduce Risk
Authors: Smith Jeff , Landry Tim , Wagner Dave
Published: December 2007

The dynamics of tip screen out frac and pack treatments provide challenges for sand control tool operations by creating forces on the sand control tools and the work-string. This paper reviews forces on the sand control tools during a frac and pack and the effects of drag, stretch, and helical buckling on the work-string before and after frac and pack operations. Case studies are presented.

Methods for determining forces on work-strings used in fracture treatments were presented in the early 1960's by Lubinski et al1. Determination of these forces assumed vertical wells. Frac and pack operations are often conducted in deviated wells which create work-string drag and result in pipe stretch or buckling. In-complete analysis of these forces can lead to premature job termination or tool failure. Guidelines are provided for packer - work-string forces, work-string drag, work-string stretch and buckling determination in typical frac and pack operations. Included are empirical data for fracture pressure prediction, work-string temperature change, friction pressure drop, and work-string to casing friction factor values.
Field Results of Separation Vessel and Multiphase Flowline Debottlenecking Using an In-line Gas/Liquid Auger Separator
Authors: Weingarten Jean S.
Published: December 2007

Field results of auger separator installations are presented which demonstrate the following new applications of in-line gas/liquid partial separation:increasing separation vessel capacity (or reducing required vessel size for a given flow rate) andreducing pressure drop in multiphase lines that transport produced hydrocarbons.

The auger separator is a device which partially separates liquid and gas, has no moving parts, and requires no power or level controls. The diameter of the separator is typically a few inches, generally about the same diameter as the line, and is installed as a spool piece in the line.

In one application, a field test was conducted where the auger separator was placed just upstream of a conventional test separator. By removing a portion of the gas upstream, the liquid capacity of the vessel was approximately doubled. In a different application, auger separators were installed to remove gas from multiphase flow lines and provide raw gas lift on the drillsite. By doing this, the amount of gas in the production line was reduced, decreasing the backpressure and increasing the capacity for produced fluids. The operating conditions before and after the installations, equipment descriptions and photos, piping layouts, and operational considerations are included. The design of the auger separators and performance comparisons to predictions from design equations are also discussed.

P. 105
Investigation into Oil/Water Separation Problems Utilizing RTD Testing and Fluid Properties
Authors: McLelland W. Greg , Garcia Melissa
Published: December 2007

Given the large volume of produced water handled at Prudhoe Bay, the oil content of the water is a critical loss control factor. For a period of ten to twelve months, one separation facility experienced severe oil loss in the produced water, with instantaneous peaks of as much as 12,000 bbls/d. Difficulty in obtaining adequate primary separation, evidenced by unacceptable oil concentrations in the separator water draws, was exacerbated by completely overloading the produced water treatment system.

To identify the cause(s) of these losses, RTD (residence time distribution) tests were conducted on all low pressure separation vessels and tankage in the produced water treating system. In addition, a series of interfacial tension and surface tension measurements were made on the fluids to which various treatment chemicals had been added. These test results, when looked at in concert, gave clear insight into the problems being experienced with effective separation. The effective residence time of a vessel is dependent upon the properties of the fluids in the vessel and these properties should always be taken into account by the engineer trouble shooting a system.

P.129
Conditioning Geostatistical Models to Two-Phase Production Data
Authors: Wu Zhan , Reynolds A.C. , Oliver D.S.
Published: December 2007

A discrete adjoint method for generating sensitivity coefficients related to two-phase flow production data is derived. The procedure is applied to calculate the sensitivity of wellbore pressure and water-oil-ratio to reservoir simulator gridblock permeabilities and porosities. Using these sensitivity coefficients, an efficient form of the Gauss-Newton algorithm is applied to generate maximum a posteriori estimates and realizations of the rock property fields conditioned to a prior geostatistical model and pressure and/or water-oil ratio data obtained under two-phase (oil and water) flow conditions.

P. 205
Evaluation of Steam Injection Process in Light Oil Reservoirs
Authors: Dehghani Kaveh , Ehrlich R.
Published: December 2007

Feasibility of steam injection for three light oil reservoirs in different geologic settings has been evaluated. These were a waterflooded deltaic sandstone, a waterflooded vuggy dolomite, and a deltaic sandstone structural trap with a gas cap.

Optimization of steam injection to take advantage of individual reservoir characteristics is demonstrated.

For the deltaic sandstone, selective flooding of channel sands with upward fining porosity gave the best results. For the vuggy dolomite, a hybrid steamflood-steam stimulation process that maximizes conductive heating of bypassed oil was found to be best. For the structural trap. up-dip steam injection below the gas cap with down dip producers showed more recovery over gravity drainage. Sensitivities of each process to uncertainties in geologic and rock-fluid parameters were also investigated. The most influential parameters were identified for examining the quality of input data and the added value of information to reduce the uncertainties.

Recent advances in reservoir characterization and modeling tools enable us to predict the performance of a Light Oil Steamflood (LOS F) more accurately than in the past, considering details of reservoir geology, fluid phase behavior, and displacement process physics. This is demonstrated through re-evaluation of a project carried out in 1985 in the Buena Vista Hills field in California where initial modeling using then current methods predicted a successful project. The re-evaluation would have correctly predicted failure as a result of early steam breakthrough.

Results show that light oil steamfloods can be designed to take advantage of post-secondary oil saturation distribution. The resulting project may be carried out in a considerably different fashion than conventional heavy oil steamfloods.

P. 279
Effect of Temperature on Heavy-Oil/Water Relative Permeabilities
Authors: Akin Serhat , Castanier Louis M. , Brigham William E.
Published: December 2007

In the first part of this study, the accuracy of the JBN technique for the determination of heavy oil/water relative permeabilities, and the effect of temperature on relative permeabilities is examined by giving numerical as well as experimental examples. Using the JBN technique leads to a false temperature dependence of relative permeability curves. In the second part, we present unsteady state relative permeability experiments with initial brine saturation at differing temperatures conducted using South Belridge sand and heavy oil. A new three step experimental technique and an analysis procedure were developed to test the effect of temperature on relative permeabilities. In this technique, an ambient temperature unsteady-state relative permeability run is conducted in the first stage, and following that the temperature is increased twice (i.e. 1220F and 1500F). Two phase saturation profiles along the sand pack are measured using a CT scanner. A commercial black oil simulator, coupled with a global optimization code is then used to estimate two phase relative permeabilities. Experimental saturation profiles, differential pressure and recovery data collected from both the ambient and higher temperature data are used in the numerical model. It has been observed that a single set of relative permeability curves can represent both the ambient and high temperature parts of the experiment. This suggests that relative permeability is not a function of temperature at least for the systems and temperature ranges tested P. 329
The E-M Field, Offshore South Africa: Review of Probabilistic and Deterministic Calculations of Hydrocarbons in Place and Reserves
Authors: Kelly R. T. , Storer A. J. , Bardwell K. A.
Published: December 2007

A significant effort is expended in the estimation of hydrocarbons initially in place and reserves (by which we mean ‘technical’ reserves in this paper), but sometimes little effort goes into leaving a clear and concise audit trail for other users, perhaps as a result of the large number of contributors to what is, by necessity, a multi-disciplined activity. The case study discussed - the E-M gas field, offshore South Africa - highlights the pitfalls in commonly used deterministic and probabilistic methods and indicates the level of appropriate detail that can be applied to each stage of the process, with particular emphasis on those parameters of greatest uncertainty. From this case study, general conclusions about the methods under discussion can be drawn. Hydrocarbons initially in place are calculated from first principles with a rigorous audit trail (which should be normal practice). Geophysical, geological, petrophysical and engineering data from seismic interpretation to reservoir fluid description are reviewed in depth and analysed statistically to ascertain appropriate distribution functions. Judgement calls are inevitably a necessary part of the exercise, and this has been handled by a committee approach in this instance. The appropriate probability functions within typical Monte Carlo simulators are reviewed, and input parameters carefully screened for the E-M field. In addition, the parametric method is applied to the hydrocarbons in place calculation and to the reserves calculation using the output from simulation runs which test critical reservoir parameters. The case study demonstrates that the parametric method is a particularly useful tool - especially for reserves evaluation when multiple simulation runs are available.
Breaking of a Paradigm: The Simultaneous Production of the Gascap and Oil Column
Authors: Billiter Travis C. , Dandona Anil K.
Published: December 2007

The conventional way to produce an oil reservoir that has a gascap is to produce only from the oil column while keeping the gascap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gascap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gascap and oil column. This methodology has application in reservoirs with a low-dip angle, relatively large gascap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. The work also demonstrates that the recovery from the gascap is minimally affected by heterogeneities in the reservoir. This is shown using geostatistical reservoir models. The effect of heterogeneities on oil recovery is also documented.

P. 431
Application of Forecasting and Uncertainty Methods to Production
Authors: Spencer J. Allan , Morgan David T.K.
Published: December 2007

Uncertainty has become an ever important subject for the oil industry as the engineer learns to use the skills of the mathematician. The use of distributions rather than single numbers, and uncertainty analysis has permeated through many common areas of the work of the oil industry.

Such methods have, for a number of years, been applied to estimate the range of reserves for discoveries. when applied to production forecasting, together with other techniques, improvements can be achieved both in the forecasts and in the understanding of the restrictions that are being placed on production. This, in turn, can lead to improved levels of production.

P. 339
Resolving Reservoir Uncertainty to Create Value
Authors: Chorn L.G. , Croft M.
Published: December 2007

Technology application focuses upon acquiring knowledge to reduce the uncertainty surrounding large capital investments in exploration and production. In practice, the industry makes incremental investments that exploit the increasing knowledge base for the asset, such as an exploration lease or a newly discovered field. Reservoir characterization reduces the uncertainty surrounding the development of a field by gathering and interpreting data from many interrogatory tools. The acquisition of that knowledge cannot be valued readily by traditional discounted cash flow (DCF) analysis and this has caused considerable problems for both the suppliers and users of technology. A new financial tool called Real options analysis is evolving which estimates the value of acquiring a knowledge base or developing a new technology. The value recognized by Real options reflects management's flexibility to reduce the uncertainties inherent in discovering and producing hydrocarbons.

Real options analysis is a decision and valuation approach that estimates the net present value of managing uncertainty. When the uncertainty of a financial outcome is large and the time to resolve the uncertainty is sufficiently long, the value of a real option can be large.

Mobil is extending Real options analysis to manage technology applications and optimize investment relative to resolving uncertainties. This article describes extensions made to the analysis technique for valuing a technology application. The methodology is illustrated with the application of integrated reservoir characterization techniques to reduce uncertainties in recoverable volume and well productivity. The Real options analysis indicates that a maximum value benefit in reducing reserve's uncertainty can occur at high expenditures. The maximum is a function of project's estimated NPV (with uncertainty), characterization analysis time, and the cost of delay.

P. 347
The "Well Learning System" - The Evolution of a Tool Into A Modern Management System for Drilling Operations
Authors: Minton R.C. , Vik R.B.
Published: December 2007

The "Well Learning System" (WLS) is a Microsoft Project adaptation formerly used to describe the processes carried out by the Drilling Engineer when planning a Drilling Operation. However, in the course of planning BP Norway's Deep Water Exploration well for the Barden prospect, the team has extended the capability and applicability of the software. It is now being used to describe, manage and report on the activities of the multi-disciplined team involved in the project; to ensure that all team members have ready access to Company polices, standards and reference manuals, and that they all have immediate access to the most up-to-date project information. It is also being used as an assurance tool, as a method of performance tracking and as a means of capturing lessons learnt throughout the planning and execution phases of the well.

In this way the tool is being used to demonstrate compliance with BPN's Drilling Management System, without the need for in depth audits, and in such a way as to be responsive to the requirements imposed by evolving organisational models.

P. 525
Optimization of Cuttings Removal by Use of Real-Time Annulus Pressure Measurements While Drilling
Authors: Pedersen B.R. , Zajaczkowski J.
Published: December 2007

This paper demonstrates how real-time monitoring of downhole annulus pressure can be used to reduce risks and optimize the drilling process especially in the extended reach applications. Field data shows how real-time pressure data are used interactively to optimize cuttings removal and adjusting mud weight. The ability to monitoring and subsequently controlling downhole circulating pressure enables tight acceptance windows between estimated pore pressure and fracture gradient.

P. 565
Why Guidelines?
Authors: Babson E.C.
Published: December 2007

This paper was prepared for the 44th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in San Francisco, Calif., April 4–5, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Some time ago I was indiscreet enough to make some comments about the proposed "Guidelines" in the hearing of Sam Sarem. Once you make an error like that, it doesn't take Sam long to nail you. So I find myself up here making a speech just because of what seemed at the time to be a minor indiscretion.

My qualifications, such as they are, for participating in this discussion are largely the result of having been around longer than most anybody. I have been working in the oil industry for forty years, many of them as an employee of a large corporation. I have worked in research, engineering, operations, and management. For the past ten years, I have been a consulting engineer. As nearly as I can see, the main difference between consulting and working for a big corporation is that a consultant seems to have a lot more bosses and their patience is shorter.

In any discussion of Guidelines to Professional Employment, two questions Professional Employment, two questions are fundamental:What is the purpose of formulating Guidelines?If the purpose is a worthwhileone, do we need formal Guidelines to accomplish it?

After all, we have been getting along without formal Guidelines for a long time, and since we are all subject to plenty of rules, regulations, guidelines, etc. already, we should hesitate to establish new ones unless they are absolutely necessary. Let us not kid ourselves. In the real world, guidelines historically become rules and rules eventually become laws. If there is not some way of bringing pressure on the recalcitrant employer, why have guidelines?
First North Slope Installed Water Injection Booster using Below Grade Electrical Submersible Pump (ESP)
Authors: Williamson Jane , Laule Bob , Hefley Mike , Hazen Beez , Richards Peter
Published: December 2007

A water injection booster pump system using a below ground "can" Electrical Submersible Centrifugal pump (ESP) will be described. This pump, an integral part of the Milne Point Unit water injection system, is the first such installation on the North Slope of Alaska. The can ESP was chosen as a speedy, flexible, low footprint, cost effective solution to increase water injection. The pump successfully increased water injection capacity to over 20,000 bpd at 3200 psi discharge, an increase from 8000 bpd at 2600 psi As a result of the project, reservoir pressure and oil production has increased substantially in the fault blocks receiving additional water injection support. The paper will provide an overview of the project design and installation, with emphasis on downhole aspects of the pump design (geotechnical, ESP, completion).

P. 381
Estimation of Formation Properties Using Multiprobe Formation Tester in Layered Reservoirs
Authors: Badaam H. , Al-Matroushi Salem , Young N. , Ayan C. , Mihcakan M. , Kuchuk Fikri J.
Published: December 2007

Vertical interference tests across stylolite zones were carried out in a number of wells using the wireline multiprobe formation tester as a part of the reservoir characterization for the pilot gas injection areas in a Middle East Carbonate reservoir. For each test, the pressure and flow rate at the sink probe and pressures at the horizontal and two vertical observation probes were recorded as a function of time. For the interpretation of the pressure measurements from these tests, a detailed reservoir model was constructed based on the field geology and openhole logs, particularly resistivity images. Vertical communication across tested zones and individual layer horizontal and vertical permeabilities are obtained. High permeability zones were identified with some lateral continuity across wells. Some zones were found to be local permeability barriers with well developed stylolite zones. The results will be used in the modeling of a pilot gas injection study.

P. 479
Subsalt Imaging Using Full Tensor Gradient and 3D Seismic Data, Mississippi Canyon, Gulf of Mexico
Authors: Prutzman John M.
Published: December 2007

Imaging of the base of salt and subsalt prospects with 3D seismic data is difficult and time consuming. The Mississippi Canyon Area was chosen to prove the value of integrating 3D full tensor gradient data with 3D seismic to enhance the geologic model for drilling and development. The full tensor gradient data was acquired by Bell Geospace using a gradiometer originally developed to navigate the U.S. Navy trident nuclear submarines. It has very high sensitivity and is able to capture meaningful high frequency data not found in normal gravimeter data. Because all nine gravity gradient tensors are measured, the data gives information on the size, shape, and edges of the salt. The gravity and gradient responses for an initial geologic model developed from 3D seismic data were subtracted from the Bell measured data. The results were used to reinterpret the seismic data and modify the geologic model until the differences were significantly reduced. The revised model reinterpreted the pay horizons as a broad anticline lying below the salt. The gradiometry data also refined the interpretation of the edge and base of salt, lowering the base as much as 1,250 feet in some areas. The final geologic model also had significant improvements in density, particularly in the shallow layers. This study proves that 3D gradiometry data provides an important independent constraint for successfully interpreting seismic data, particularly in areas of poorly imaged seismic reflectors.
Multiphase Transportation: Hydrate Plugging Prevention Through Crude Oil Natural Surfactants
Authors: Leporcher E.M. , Peytavy J.L. , Mollier Y. , Sjoblom J. , Labes-Carrier C.
Published: December 2007

Multiphase transportation is more and more contemplated in the development of oil and gas fields both in conventional and frontier areas (from remote satellite fields to deep offshore). This new environment has set forward new challenges in the field of hydrate plugging prevention in subsea flowlines. Increases of transportation distances and water depths place the fluids well inside the hydrate formation domain, and hence threaten flow in multiphase export lines.

In such conditions, conventional hydrate prevention (alcohols, insulation, heating) can become very expensive and can in some cases jeopardize the economy of the project. To challenge this anticipated situation, the oil and gas industry has been looking for low dosage inhibitors: kinetic inhibitors which can delay hydrate crystallization, anti-agglomerants which let the hydrate crystallize but ensure their transportability in a slurry.

This second process creates a water-in-oil emulsion which remains a transportable suspension after crossing the hydrate equilibrium curve.

We have investigated whether this process could occur by itself with some surfactants naturally present within some crudes. Some research works have confirmed that some "natural surfactants" such as resins and asphaltenes have properties similar to synthetic surfactants.

Since 95, extensive experimental work has been done at the University of Bergen (1, 2) and Elf research center (3) on a 1" loop with different crudes and fluid blends. The hydrodynamic tests have demonstrated the capability of natural surfactants to prevent hydrate plugging. Based on these results, an experimental methodology to evaluate hydrate transportability of a given crude has been developed.

This method could reduce the need of inhibitors during the first years of production and thus result in large savings. With the present development of subsea-water separation technology, this process could further become a standalone alternative.

P. 509
In Situ Stress and Moduli: Comparison of Values Derived from Multiple Techniques
Authors: Warpinski N.R. , Peterson R.E. , Branagan P.T , Engler B.P. , Wolhart S.L.
Published: December 2007

This study compares the moduli and stresses obtained from dynamic measurements (e.g., logs or tomograms) and static tests (microfracture stress tests, core tri-axial compression tests) at M-Site, where there is a full suite of both types of data as well as other supporting information. The study shows that the dynamic moduli and log-derived stresses are considerably different from the measured in situ values as determined from microfracture stress tests. 2-D images of moduli and stress were also calculated from p-wave and s-wave tomograms, but the primary value of these results is in the qualitative description of the reservoir. The choice of modulus and stress values has a significant effect on processes such as hydraulic fracturing.

P. 569
Scale Inhibitor Selection for Continuous and Downhole Squeeze Application in HP/HT Conditions
Authors: Graham G.M. , Dyer S.J. , Sorbie K.S. , Sablerolle W.R. , Shone P. , Frigo D.
Published: December 2007

With the development of a number of new HT/HP fields in the North Sea, for example the ETAP fields (Eastern Trough Area Project), a number of important "scale" control issues have arisen. In addition to harsh downhole conditions (T - 180 C; P - 13,000 psi), high salinity formation water chemistries indicate that the control of inorganic precipitates in these systems will be very important. The form of the inorganic precipitates are predicted to include the more Cornnjton oilfield scales (BaSO4 and CaCO3). In addition the very high salinity of several of the formation brines (TDS - 350,000 ppm) can result in halite precipitation (NaCl(s)). This occurs either as a result of water flash-off into the gas phase as pressure decreases during production or simply due to reduced halite solubility as temperature and pressure decline during production.

This paper discusses the potential scaling problem associated with these harsh reservoir conditions and outlines various solutions for treating such reservoirs using conventional scale inhibitor technology. A series of different generic scale inhibitor chemistries have been assessed for their potential application in such reservoirs. The assessment has involved a range of laboratory procedures including thermal stability, brine compatibility, carbonate and sulphate inhibition efficiency testing. These tests were conducted at temperatures up to 180C. The laboratory screening procedures led to the selection of the most appropriate generic chemical types which are applicable for scale inhibitor treatment under HP/HT reservoir conditions. Further studies then examined the most appropriate species for application downhole as squeeze treatment chemicals under HP/HT conditions. This included static adsorption tests conducted at temperatures and pressures ranging from 950C at saturated vapour pressure (SVP) to 180C and 7,500 psi. Reservoir conditioned core flooding studies were conducted on the two most appropriate species in order to assess formation damage issues and to derive their respective adsorption isotherms in order to model potential squeeze lifetimes.

P. 645
Waxy Crude Cold Start: Assessment Through Gel Structural Properties
Authors: Cazaux G. , Barre L. , Brucy F.
Published: December 2007

During prolonged shut-down of pipeline transporting waxy crude oils and cooling, crystals of paraffins are formed within the fluid bulk and can interlock into a continuous gel-like network. Then, a restarting pressure is required to break the gel and resume flow, the resistance of gel to flow naturally resulting from its structure state. This paper addresses the understanding of the mechanisms of cold start-up of flow, through the assessment of the structural properties of the gelled oil.

A set of laboratory techniques has been used to investigate the building-up of the gel structure after a cooling at rest. Two stock tank crude oils were tested for this investigation. As a result, the experimental data are combined into a description model of the development of the gel network as temperature decreases. Physical significance of Wax Appearance Temperatures is discussed from this model.

It is concluded that the relevant parameters to build a structural model and understand the flow properties of these gelly oils are size, shapes (ratio axes) and number of paraffin crystals, and that they depend on temperature and cooling history.

P. 729
Evaluation of Long-Term Effluent Water Disposal Options in the Greater Burgan Field
Authors: Brown D.R. , Jones P.S. , Al-Saif K.
Published: December 2007

Effluent, which is a mixture of produced and brackish water from the Greater Burgan Field operations, has historically been disposed of through the use of evaporation pits. While this has worked adequately in the past, some of the Gathering Centers (GC) are unable to handle the ever increasing volumes with evaporation pits. Between environmental concerns, the decreasing capacity of the pits and the increasing volume of water, alternative disposal methods needed to be considered. Kuwait Oil Company (KOC) embarked on a study to look at the various options of disposing of its increasing volume of effluent water. A multidisciplinary team composed of Reservoir Engineers, Geologists, Operations personnel and Facility Engineers was assembled with the task of developing recommendations. Their efforts encompassed a review of alternative disposal options, reservoir assessment, on-site coreflood tests, two pilot disposal projects, and a survey of water quality.

P. 555
A Method for Determining Average Reservoir Pressure and Inflow Performance from Historical Surface Flowing Data in the Gomez (Ellenburger) Field, Pecos County, Texas
Authors: Adams L.S. , Norris H.L. , Schumacher B.W.
Published: December 2007

This paper presents the development and application of a method for determining average reservoir pressure and inflow performance parameters from historical surface flowing data for deep, high-temperature, gas wells located in the Gomez (Ellenburger) Field, Pecos County, Texas. This method provided suitable average reservoir pressure, improved p/z versus Gp data, and inflow performance optimization where a significant lack of reservoir data existed. The versatility, risk reduction, and cost-effectiveness of this methodology are also discussed.

P. 577
A Generalized Material Balance Equation for Coal Seam Gas Reservoirs
Authors: Penuela G. , Ordonez A. , Bejarano A.
Published: December 2007

During the last few years, research has been done on generalized material balance equations for conventional oil and gas reservoirs in order to improve the reservoir performance analysis. However, those equations are inappropriate for coal seam gas (CSG) reservoirs. To address this limitation, a generalized material balance equation (GMBE) for CSG reservoirs was developed. This work is based on a mathematical development and the straight-line method, published previously and widespread used for conventional reservoirs.

Three validation examples of the proposed equation were designed. They show the new equation has the following advantages:it is applicable to CSG reservoirs in saturated, equilibrium, and undersaturated conditions,it is applicable to any type of coalbed without restriction on especial diffusion constant values,existent equations are particular cases of the generalized equation evaluated under certain restrictions, andits reorganization is analogous to the popular straight- line method for conventional reservoirs.

P. 621