bluuebunny/crossref_metadata_2025 huggingface dataset:
The Formulation of a Thermal Simulation Model in a Vectorized, General Purpose Reservoir Simulator
Authors: Chien M. C. H. , Yardumian H. E. , Chung E. Y. , Todd W. W.
Published: December 2007

This paper describes the formulation of a thermal simulation model in a vectorized, general purpose reservoir simulator. The thermal simulation model, an option in this general purpose simulator, is equivalent to a three-phase, three-dimensional, thermal compositional simulator. It has a variety of options for modeling fluid properties and phase behavior. These include the EOS method (the three parameter Peng-Robinson equation of state) and the non-EOS methods (table look-ups and correlations). The model also considers the solubility of water in the oil phase. Furthermore, all calculations are extensively vectorized.

Test problems including problem No. 3 of the Fourth SPE Comparative Solution Project are used to evaluate the effectiveness of vectorization. Results show that the vectorized calculations outperform the nonvectorized ones by about an order of magnitude in computational speed on the Cray X-MP/48. Overall, this thermal model runs about 5 times faster than a previously reported conventional, partially vectorized thermal simulator.

Finally, the use of this thermal simulation option to study the sensitivity of simulation results to various fluid property and phase behavior calculation methods is illustrated with a hypothetical problem. Results show that simulation results can be used to determine the importance of different K-value and volume calculation methods, and the inclusion of water-in-oil solubility.
A Comprehensive Wellbore/Reservoir Simulator
Authors: Stone T. W. , Edmunds N. R. , Kristoff B. J.
Published: December 2007

This paper describes a fully implicit, three dimensional thermal numerical model for simulating flow through a porous media and through a wellbore. Darcy's law is used together with conservation of energy and mass to model flow in the porous media. The wellbore simulator is a time dependent, thermal, three-phase, one dimensional model which conserves energy, momentum of all phases and mass. Wellbore grid blocks are embedded in reservoir grid blocks. Variables in the reservoir and wellbore are solved for simultaneously. Many options are included in the wellbore simulator including the ability to model parallel flow in inner tubing and outer annuli and specification of slant angles or other parameters per wellbore grid block. This coupled model is targeted mainly at horizontal well or other applications in which a high degree of dynamic interaction occurs between the wellbore and reservoir.
Compositional Modeling of High-Temperature Gas-Condensate Reservoirs With Water Vaporization
Authors: Betté S. , Heinemann R. F.
Published: December 2007

An equation of state compositional model capable of simulating water vaporization is presented. This approach treats water as a component among other species in the hydrocarbon phases and allows for mass transfer between the aqueous phase and the hydrocarbon phases. The model is validated against single cell PVT experiments. The impact of this formulation on the basic compositional model equations and the solution of the nonlinear and linear system of equations will be discussed. The simulator incorporates a sophisticated well management scheme with a model of a gas plant to evaluate performance under various facility constraints.

The application of this simulator in the management of the Arun gas-condensate reservoir in Indonesia is presented. The first phase of this 5000 cell, 8 component, 50 well study involves establishing reservoir parameters by matching historical pressure performance of individual wells. Predicted total field wellstream composition and cluster condensate gas ratios match historical data very well. The accuracy with which this formulation simulates water vaporization is demonstrated by comparing predicted and measured water vapor production. In the second phase, the reservoir model is used to predict future performance. This simulator has the unique capability of simulating gas processing plant operation to calculate and predict product streams such as LNG, LPG and stabilized condensate. This feature allows one to specify future demand for a product such as LNG. The specification is translated into exact individual well production rates based on their produced well stream composition. Water evaporation has a significant effect on reservoir performance and an even greater effect on tubing flow performance. The model predicts injection gas profiles, extent of retrograde condensation, subsequent revaporization by injection gas, and composition and saturation distributions across the reservoir. The utility of the model predictions in the design of surface facilities, in the determination of well requirements, and in developing strategies to improve product recoveries will be discussed.
Use of Parameter Gradients for Reservoir History Matching
Authors: Anterion F. , Eymard R. , Karcher B.
Published: December 2007

In reservoir simulation, history matching has long been performed in an empirical way. Applying inverse problem methods to reservoir simulation requires the calculation of gradients of observations at producing wells with respect to reservoir characteristics, which leads to a local linearisation of the full non linear reservoir simulation problem.

This paper describes a rigorous analytical method for the computation of gradients. The gradient calculation has been implemented in the fully implicit, 3-phase, 3-dimensional reservoir simulator, SCORE, in a way which leads to significantly reduced computation time compared to other methods.

The second part of the paper reports on a preliminary attempt at computer aided history matching, based upon a meta simulator which uses the calculated values of the gradients and a minimisation procedure together with several extrapolation laws. Two applications of the method are presented. They serve to demonstrate that the experience of the reservoir engineer cannot be replaced by such a method, used in an automatic way, because the system cannot decide which parameters should be changed. However, once an appropriate choice had been made, the meta-simulator provided an accurate estimate of the modified parameters which had to be used in order to simulate precisely the observed results.

Application of this method increased the accuracy of the history match whilst significantly reducing both the number of computer runs and the total processing time required compared to other methods.
Acid Reactions and Damage Removal in Sandstones: A Model for Selecting the Acid Formulation
Authors: Perthuis H. , Touboul E. , Piot B.
Published: December 2007

For removing a clay-based damage in sandstone formations, diluted HCl-HF acids are often recommended when the standard 12%HCl-3%HF acid is found or thought to be incompatible with the formation through one of the possible mechanisms: deconsolidation, fines migration or by-product precipitation. But the dissolving power of such acids, which varies with rock mineralogy, is generally not assessed.

Dissolution kinetics parameters for aluminosilicate minerals with these acids, as well as with other acids which are able to progressively generate HF, have been verified and established as a function of temperature, mineral concentration and mineral surface area, acid concentration and ionic strength (catalytic effect).

These complete acid-rock reaction parameters have been implemented into a dissolution simulator coupling chemical reactions and flow in a porous medium. This implementation has been validated against flow tests in linear geometry. The dissolution power of commercial acid formulations can thus be compared during simulations of real treatments and the best system for effective damage removal be selected. Examples show how treatment parameters (permeability, porosity, clay and silica content in the damaged area) are affected to varying degrees by these different acid solutions.
A New Nondamaging Particulate Fluid-Loss Additive
Authors: Williamson C. D. , Allenson S. J.
Published: December 2007

Recently there has been a push to pursue a cleaner fracturing system. This includes using a fluid loss additive that is nondamaging. Conventional particulate fluid loss additives are usually made up of inert materials such as silica flour or clay. These types of materials are well known for their ability to plug pore spaces and enhance the formation of a filter cake. Once flow back is started, however, these materials can stay in place possibly causing reduced permeability. Since the materials are inert, they can remain in the pore space for a long period of time. To circumvent these problems, a non-formation damaging particulate fluid loss additive is needed.

This paper describes the development of a new non-formation damaging particulate fluid loss additive that is degradable under downhole conditions. This fluid loss additive is a blend of various starches and substituted starches with a broad particle size distribution ranging from 5 to 200 microns and with a portion of the starches being water soluble.

A synergistic effect occurs between the starches and modified starches that comprise the subject fluid loss additive. This is evident from results seen in standard API fluid loss tests. The blend provides significantly lower spurt losses and Cw values than any of the individual components.

Additional laboratory studies on the non-damaging aspect of this fluid loss additive have shown excellent degradation results with respect to time, temperature, and addition of an enzyme or persulfate.
Inorganic Chemical Souring of Oil Reservoirs
Authors: Marsland S. D. , Dawe R. A. , Kelsall G. H.
Published: December 2007

Many North Sea oil production reservoirs are producing increasing quantities of hydrogen sulphide, perhaps as high as 30 ppm, although the oil itself is naturally sweet. This high level is endangering the sales of oil and gas, giving rise to enhanced corrosion effects in pipelines and production facilities as well as causing concern for health and safety.

The mechanism put forward in this paper for hydrogen sulphide generation within the reservoir is via Non-oxidative dissolution of formation components:

MS + 2 H + ↔ M 2 + + H 2 S

(where MS. is especially components containing iron sulphide species such as Fe1 − xS, FeS1 − x and FeS2)

The acidic component in the above reactions is provided either from the injection water on breakthrough, or degradation species from injected components such as biocides and corrosion and scale inhibitors.

The objectives of this continuing study are to investigate the kinetics and mechanisms of formation dissolution in reservoir environments of high temperature, high pressure and high ionic concentration based on:

Preparing pure iron sulphides of known stoichiometry and homogeneity Using generated thermodynamics diagrams to predict the behaviour of the iron-sulphur-water system at any required conditions relevant to the reservoirs Combining the thermodynamic predictions of 2) with experimental work utilising 1) in a rotating-ring-disc electrode assembly to determine the mechanism and kinetics of the dissolution reactions

This paper presents the preliminary work on this study.
Hydrolytic Stability of Ethoxylated Sulfonates
Authors: Talley L. D.
Published: December 2007

This paper discusses the reactions that are responsible for the decomposition of alkyl ethoxylated sulfonates under reservoir conditions. Experimental results are presented to substantiate the derivation of several kinetics equations. The equations form the basis for a mathematical model capable of predicting the lifetime of an ethoxylated sulfonate at’ all reservoir temperatures, salinities and brine pH.
What Is the Rheology of Foam in Porous Media? A Micromodel Study
Authors: Armitage P. , Dawe R. A.
Published: December 2007

Snap-off, a bubble/lamella generating process is believed to be responsible for the generation of strong foams in porous media. It is thought to be dependent upon a number of system parameters such as the pore geometry, surfactant concentration, wetting fluid viscosity, flow rate and the quality (gas to liquid flow rate ratio). A study has been conducted to assess the degree of influence these parameters have on the process of snap-off.

This paper reports in detail a number of qualitative and quantitative results obtained from a 2-D mechanistic study of the flow of an interface (constituent part of a foam) through various simple rectangular pore-throat pore-body junctions. The study was conducted using 2-D micromodels made from a clear, araldite epoxy resin so that visual evidence of the results could be recorded.

Roof's theoretical analysis of the static geometric criterion required for snap-off to occur has been modified to accommodate our physical models and its predictive capabilities explored in a dynamic situation. Also the pressure regimes manifest in the process of snap-off have been recorded as a function of time in an attempt to quantify the events more fully.

The findings reported here give further insight into one of the major pore-scale foam generating mechanisms.
Discount Rates, Cost of Capital, and Property Acquisition Evaluations
Authors: Miller R. J. , Vasquez R.
Published: December 2007

The purpose of this paper is to examine the role of the discount rate in determining the fair market value of a producing oil and gas property; to assess the validity of a discount rate based on a derived source and on an observed or market source, and to evaluate the relationship between discount rates obtained from these two sources. The derivation of a discount rate based on a Cost of Capital approach is compared to the observed effective rate-of-return obtained from analysis of actual producing property acquisitions to (1) determine if a rational relationship occurs between discount rates obtained from the two methods, and (2) how the discount rates obtained from the two methods may reflect changes in the oil and gas industry. The use of derived and observed discount rates in FMV analysis is examined and discussed, particularly as it applies to property acquisitions.

The source of the study reported by this paper is an annual review and analysis of oil and gas property transactions in California which is done for the Western Oil and Gas Association (WOGA) and the California Independent Producers Association (CIPA) and which is generally referred to as the "WOGA Study."(1) The WOGA study attempts to define market economic parameters used in the acquisition of producing properties in California. The study examines several economic factors, including price/cost projections, but particular attention is given to the effective discount rate related to the determination of Fair Market Value. This market data forms the basis for industry recommendations to the county tax assessors regarding the methods and parameters to be used in appraising oil and gas properties for ad valorem taxes. The objective of industry and assessors is to define a method, and the economic parameters necessary, to determine the present value and, more to the point, the Fair Market Value (FMV) of an oil and gas producing property. The same concern for proper evaluation methods and appropriate economic functions is thought to exist throughout the industry where operators, interest owners, financiers, and investors need to determine the market values of producing properties.

The study concludes that:

The pre-tax cost of capital of a company or industry group provides a reasonable "base" discount rate for evaluation of producing properties. The effective FMV ROR on actual acquisitions consistently exceeds pre-tax cost of capital by several percentage points. The divergence between observed ROR and cost of capital appears to vary depending, at least in part, on the perceived risk in the property appraisal. Risk adjustments on a project or other basis, if identifiable, are not quantifiable from the data available. The Cost of Capital for the oil and gas industry, from a sample group, averaged 19–20% for 1983–1985 declining to 14.9% in 1987. The market discount rate from actual sales of properties for the 1983–1987 period, ranged between 26–28% which provided a reasonable and safe return above the cost of capital.
Fiscal Risk and the Stability of Contractural Arrangements for Petroleum Exploration and Development
Authors: Cavoulacos P. E. , Blitzer C. R. , Laughton D. G.
Published: December 2007

The objective of this paper is to develop a methodology to assess the impact of fiscal risk, the risk of contractual non-performance by a host government, on the value and stability of contracts for petroleum investment. In the proposed fiscal risk model, the host government may appropriate a share of excess profits (resulting from perceived price or discovery windfalls) higher than that specified in stated contract terms. A valuation framework similar to that used to price options and futures in financial markets is used. Various components of the project are valued as contingent claims on the revenue stream of the developed field. Four fiscal regimes -- royalty, production sharing, service and resource rent tax -- were designed to give the same asset value to the foreign oil company under stated contract terms; however, when fiscal risk is taken into account, this value can be substantially lower. The royalty and production-sharing contracts are quite unstable because a large fraction of the initial value accruing to oil companies under stated contract terms comes from the possibility of large discoveries, where fiscal risk is most severe. The resource rent tax and the service contract are more stable because both fiscal regimes generate the bulk of oil company value from the possibility of small and medium discoveries. The stability of the production-sharing contract can be enhanced substantially if the host government share of profit oil is set by a progressive sliding-scale schedule. In general, contract stability is enhanced if the government explicitly bears much of the oil price and discovery risk.
Quantitative Analysis of Performance of Polymer Slug Injection
Authors: Lutchmansingh P. M. , Marietta C. , Ertekin T. , Abou-Kassem J. H.
Published: December 2007

The literature reveals a number of criteria used to screen oil reservoirs for polymer injection. The qualitative response of polymer injection process for a given field parameter is also implied. This paper presents a quantitative analysis of the performance of an oil reservoir undergoing polymer slug injection due to variations of parameters used for screening. The reservoir performance is represented by the behavior of oil recovery, WOR and oil production rate. These performance parameters are usually used to determine the economics and economic limit of an enhanced oil recovery project. The field parameters considered for analysis in this study include reservoir permeability (230 – 2300 md), oil viscosity (25 – 100 cp), polymer viscosity (1.45 – 4.8 cp), rock adsorption characteristics (0 – 0.0001 lb/lb rock), polymer slug size of constant concentration (0.1 – 0.4 PV), combination of polymer slug size and concentration such that the injected polymer is constant, and polymer slug program.

In this study a number of numerical exercises were conducted using the reservoir rock and fluid data for the Lower Huntington Beach Garfield zone in two dimensions. A field parameter is varied within the limits of the screening criteria and the response of the reservoir is analyzed.

It is found that the reservoir permeability is of paramount importance to the success or failure of polymer injection as an enhanced oil recovery method. The analysis of the behavior of sandface pressure for low permeability reservoirs provides interpretation of the plugging effects observed in the field. The performance of polymer injection is improved when a polymer slug program aiming at protecting the initial slug by graded buffers is implemented. Finally, our numerical experimentation confirms the widely held view of using 0.70 pore volume injected as a criterion to terminate a polymer injection project.
Fluid Flow Considerations in Hydraulic Fracturing
Authors: Nolte Kenneth G.
Published: December 2007

Significant progress has been made over the past decade in the understanding and modeling of rock failure and deformation during hydraulic fracturing. This progress resulted from a large investment in theoretical, laboratory, and field research programs conducted by private, government and university groups. By comparison, relatively small investments or progress has been made in the companion area of fluid flow in the fracture. To bring the level of understanding for fluid flow to that of rock mechanics, and provide the basis for another major advance in fracturing technology, significant and focused investigations of fluid flow are required.

The purpose of this paper is to review the various aspects of fluid flow within the fracture, provide several relevant pieces of new information, and to identify areas for additional research. The areas considered are the effects of slip flow; proppant on viscosity; width variations on the velocity profile and the pressure gradient; proppant transport and fall after shut-in; particle migration for viscoelastic fluids; and fluid loss.
An Improved Technique for the Evaluation of Performance Characteristics and Optimum Selection of Sucker-Rod Pumping Well Systems
Authors: Lekia S. D. L. , Day J. J.
Published: December 2007

An improved method is presented for the evaluation of performance characteristics and optimum selection of sucker-rod pumping well systems. The procedure is conceptually general for all class I lever (conventional) systems and for the Mark II type of the class III lever systems. The procedure can easily be modified for any kind of special surface pumping unit.

This study uses basic sucker-rod theory already presented in the literature. The new approach, however, groups the most important variables affecting the operation of a total sucker rod pumping well system (from the prime mover to the downhole pump) into eleven dimensionless numbers which are used to aid the simulation of performance characteristics and design parameters. The final results consist of design parameters for various rod size-pump depth-production rate combinations from which an optimum pumping mode is selected. The selection of the optimum pumping mode is based on an optimization criterion proposed in this paper.

Based on limited specified information on a well being considered for the installation of a rod pumping system, the method presented can be used to select a total sucker rod pumping system that will optimize both production and longevity of all parts of the system. The procedure minimizes the design of incompatible parts that very frequently leads to system failures. For already existing installations, the method furnishes information on pumping speed, counter-balance weight, polished rod stroke, etc., for setting a new optimum operation.
An Overview of GRI's Comprehensive Study Well Program in the Devonian Shales of the Appalachian Basin
Authors: Lancaster D. E.
Published: December 2007

This paper presents an overview of the Gas Research Institute's (GRI's) Comprehensive Study Well (CSW) program in the Devonian Shales of the Appalachian Basin. Initiated in mid-1987, the CSW program is a planned series of highly instrumented study wells drilled in cooperation with industry partners. Extensive data are being collected and special experiments are being conducted on each CSW with the objectives of identifying geologic production controls, refining formation evaluation tools, and improving stimulation practices in the Devonian Shales. The focus of stimulation research in the CSW program is on pumping larger treatments carrying more sand at higher concentrations, developing an optimal fluid system for the Devonian Shales, and improving quality control.

This paper reviews the progress of the CSW program thus far and focuses particularly on the CSW No. 2 in Calhoun County, WV, which is the well studied most completely to date. The fracture treatment pumped on the CSW No. 2 demonstrates that large, high sand concentration treatments can be pumped successfully in the Devonian Shales; however, optimizing the fracturing fluid system and improving liquid cleanup remain important unsolved problems requiring additional study.
Downhole Motors Increase ROP and Reduce Cost Per Foot in the Austin Chalk Trend
Authors: Bayoud B. B. , Staiger L. W.
Published: December 2007

With currently depressed oil prices it is more important than ever for operating companies and drilling contractors to find ways of reducing drilling costs. By using some relatively new techniques, including computer-assisted planning aids and downhole motors with polycrystalline diamond compact (PDC) bits, one drilling contractor reduced cost-per-foot by 20% in the Austin Chalk Trend.

Technological advances in downhole motor designs have expanded their use as effective alternatives to rotary drilling in straight-hole and long-interval drilling applications in the Midway Shale and Austin Chalk Formations. The full potential of these motors, which for years have been used successfully in a variety of directional applications, can be tapped only through proper system design, planning and operating techniques.

The key to optimizing downhole motor performance is a systems approach that encompasses motor/PDC bit selection, hydraulics, operations, breakeven cost analysis and projected results. Results of this type of planning can be seen in the following case history data that show the use of downhole motors offers straighter holes, increased penetration rates, fewer washouts, longer on-bottom time and reduced casing/drill pipe wear when compared to conventional rotary drilling operations.

This paper describes the results of a series of wells drilled by a drilling contractor and how downhole motors reduced cost-per-foot by increasing the rate of penetration 50% to 100% in the Midway Shale and Austin Chalk Formations.
Curved Cutters Extend Range of Formations Drilled with PDC Bits
Authors: Knowlton R. H. , Kester R.
Published: December 2007

For the past few years the industry has been trying to extend the operating range of polycrystalline diamond compact (PDC) bits in terms of formations that can be drilled. Initially, the direction was uphole to the softer formations where the high standoff blade bits and large diameter PDC bits have proven economic. The next step is to extend downhole where the formations are harder and generate more heat. Typically, either tungsten carbide insert (TCI) bits or natural diamond bits are used in these harder formations because the heat degrades the polycrystalline diamond compact cutters. However, insert bits tend to be short-lived and require tripping more often than is satisfactory and diamond bits have penetration rates that are slower than desirable.

Bits using PDC cutters with enhanced thermal stability and a radius of curvature on the diamond table have demonstrated a significant economic impact in many harder formations. The diamond wafer is shaped like a dome and set in the bit in place of the conventional, flat PDC cutters. The dome shape dissipates heat better, facilitates more efficient mechanical cuttings removal and drills with a constant rate of penetration throughout the life of the cutter due to the variable rake angle.

In addition to extensive laboratory testing, a rigorous field-test program was undertaken to determine the significance of this new development. Field-test results are presented from Northern Europe and the lower Wilcox Frio sands and other formations of South Texas.
Incentive Approach to Drill Fluids Management: An Experience in Central North Sea
Authors: Geehan T. , Dudleson W. J. , Boyington W. H. , Gilmour A. , McKee J. D. A.
Published: December 2007

The paper describes a modern approach to the operation of drilling fluid at the rig site in which the drilling contractor furnished a total fluids management package inclusive of engineering services, computerised reporting techniques plus all required solids control equipment. The fluids engineering included both drilling fluid engineering and solids control optimisation with the required monitoring of oil based fluid usage and oil discharge to the marine environment.
Applications of a Real Time Wellbore Friction Analysis
Authors: Falconer I. G. , Belaskie J. P. , Variava F.
Published: December 2007

An interpretation technique to determine the friction losses in the drillstring, on a foot-by-foot basis at the wellsite, was proposed at the 1987 SPE/IADC drilling conference (SPE/IADC 16114). Since then the technique has been used commercially on over 40 wells throughout the world. The interpretation uses realtime measurement while drilling (MWD) and surface measurements of weight-on-bit and torque to compute a rotating friction factor and a sliding friction factor while drilling.

This paper describes commercial applications and limitations of the technique. Case histories are drawn from wells drilled in the Gulf Coast, East Canada, South America and Africa. The results illustrate how the technique can be used to: –detect the onset of sticking problems and avoid stuck pipe–optimize bit performance and avoid unnecessary trips–optimize various hole conditioning techniques
Case History of Horizontal Wells Drilled With Navigation Technology in European Operations
Authors: Ehlers R. , Kracht L. , Witte J.
Published: December 2007

This paper describes case histories of four horizontal wells in Europe in which directional and economic objectives were achieved using steerable Navigation Drilling Systems (NDS).

These four wells, part of a multi-well program, featured build-up rates (BURs) of 2-16 degrees/100 ft. (30m), with lateral sections ranging from 440 ft. to 2650 ft. (734-807m). Existing Navigation Drilling System technology was used to achieve BURs of 2-6 degrees/100 ft. (30m), while newly developed Navigation motors were used for BURs of 8-16 degrees/100 ft. (30m).

Case histories #1 and #2 examine two new wells in which existing NDS technology was used from kickoff to closely follow the planned trajectory while reducing torque and drag — the limiting factors for achieving horizontal reach.

In case histories #3 and #4, fixed-angle and steerable medium-radius angle-build motors were used to achieve the higher BURs in two redrills of existing wellbores. To maintain wellbore trajectory, the steerable system can be oriented or rotated in high build-up sections to adjust inclination angle and direction without tripping.

In the multi-well program referenced for this paper, the NDS drilled a combined total of 32,677 ft. (9963m) of wellbore, including 16,926 ft. (5153m) of horizontal footage, and achieved all directional requirements. Following the case histories of the four representative wells, the paper summarizes key factors in wellpath design, engineering planning and equipment selection that contributed to the success of the wells.
MODU Drilling Rig Downtime: An Objective Analytical Approach
Authors: Dew L. L. , Childers M. A.
Published: December 2007

For the past 2 1/2 years and over 250,000 MODU operating hours, which included up to 8 floating drilling rigs and 17 bottom sitting drilling rigs, downtime data was inputted into a defined matrix for analysis. By use of 6 categories (drilling, subsea, mechanical/electrical, etc.) and 5 causes (operation, manufacturer/warranty, maintenance, etc.) of downtime a 6 by 5 matrix was developed to pinpoint fleet wide as well as individual rig problem areas. Downtime data was inputted into the computer weekly as well as accidents, lost time accidents, rig status and "flags" of interest that include up to 100 different printout options. Each downtime incident has a succinct description with corresponding corrective action. The system has proven objective, useful in spotting problem areas, and with its strict definitions very repeatable. With the aid of the downtime system and reinforcement by the companies Preventative Maintenance Program, downtime LTA's and accident rates have all decreased.
Pin-up Drillstring Technology: Design, Application, and Case Histories
Authors: Dudman R. A. , Stull T. , Keane T.
Published: December 2007

Conventional drillstrings frequently pose problems when used to drill relatively small size holes. Pin Up, a new, simple technology, affords economical solutions to problematic hole sizes and conditions. The improvement realized by using Pin Up drillstrings is helping the industry drill higher quality wells, while lowering drilling cost.
Incentive Drilling Operations in Remote Locations
Authors: Marshall D. W.
Published: December 2007

The drilling of wells on incentive contracts has become increasingly common during the past several years. The motives for this trendaway from conventional day rate contracts differ for both the operator and the contractor but for a mutually beneficial result - the operator drills a cheaper well and the contractor has a chance to increase his revenue, or at least reduce his losses.

This paper examines the incentive drilling concept in general andspecifically considers the mutual benefits to be gained by both the operator and the contractor in an incentive contract in remote locations. At the same time the problems and risks of such operations arediscussed and compared with the more conventional incentive operations in the U.S. using, as an example, a recently completed turnkey well drilled by SedcoForex in Senegal.
Lightened Fluid Hydraulics and Inclined Boreholes
Authors: Rankin M. D. , Friesenhahn T. J. , Price W. R.
Published: December 2007

This paper discusses the use of fluids with densities less than that of water as a circulating medium in horizontal wells. The significance of inclined geometry as a determinant of pressure loss and hole cleaning efficiency is discussed as are the results of laboratory simulations.
Optimizing Operator/Contractor Relationships
Authors: Burris K. B. , Welter C. M.
Published: December 2007

The paper that we wish to present concerns operator/contractor relationships. Specifically it will define the proper attitudes of both parties towards communications, bidding procedures, pre-spud conferences, contract per-formance, billing procedures and contract eval-uation.

Information on the above will be derived from actual experience. This, paper will possibly differ from any presented in the past since it deals more in management philosophy rather than technical engineering data.

The results to be shown in this paper will be that optimized operator/contractor relation-ships lead to greater efficiency and lower costs for the operator plus a more profitable operation for the contractor.
EPA Offshore Effluent Guidelines for Mud and Cuttings Discharges: A Regulatory Impact Model
Authors: Randolph T. M. , Simpson J. P.
Published: December 2007

Effluent guidelines for discharges of muds and cuttings offshore are under development. The impact of the proposed guidelines is predicted by a model developed as part of the API comments on the 1988 EPA proposal. A preliminary run of this model shows that 25 percent of the drilling wastes will be hauled for onshore disposal, rather than discharged.
Land Treatment of Oil-Based Drill Cuttings
Authors: Bleckmann C. A. , Gawel L. J. , Whitfill D. L. , Swindoll C. M.
Published: December 2007

Land treatment was successfully tested for treatment and disposal of low toxicity oil-based drill cuttings and reserve pit mud. Oil content of the soil/waste mixture was reduced 84 to 97% over one year. Metals of environmental concern did not migrate vertically or horizontally, even after record rainfall events that occurred shortly after waste application.

During the pilot scale test, cuttings, cuttings plus metals and oil spikes, and reserve pit wastes, were applied to 10' x 10' plots. Plow zone (0-6"), subplow zone (6-12", 12-18") and downslope (5', 50', and 100') samples were taken periodically during the year-long study. Waste applications were based on Oklahoma State regulations governing treatment of such wastes.
Drilling Efficiency Study Reduces Drilling Cost in Colombia
Authors: Hogan S. K.
Published: December 2007

In August. 1986, Tenneco Oil Company's subsidiary, Hocol, conducted a drilling efficiency study of the 32 wells drilled in its San Francisco field near Neiva, Colombia.1 The objective set forth in the study was to reduce the average precompleted well cost from $294,000 per well to $173,150 per well (41% reduction). Since the study was published, the average well cost of six wells was reduced to $239,300 (19% reduction), and the best well cost (SF 48) was reduced to $201,400 (32% reduction). (FIGURE 1)
Effect of Flow Properties on Drillpipe Neutral Point
Authors: Blick E. F. , Shams Q.
Published: December 2007

For the past half century drilling engineers have been computing the required length of drill collars based upon a formula which assumes that the bouyed weight below the neutral point is equal to the weight-on-the-bit (WOB). However, a theory developed in 1950 indicates that the neutral point changes in tubulars when the pressure on the inside wall is different from the outside pressure. Using this theory, this paper proves that the neutral point in drill pipe always moves up the drill string when the mud pump is turned on and it can even move up into the drill pipe. The worst conditions occur in shallow wells, with low WOB, high pump pressure using max jet impact force hydraulics.
Mechanization Replaces the Casing Crew: Experience With the Casing Roughneck System on Polar Pioneer
Authors: Price M. J.
Published: December 2007

This paper contains a description and evaluation of a mechanized system which gives the drilicrew the means to run a casing string without the assistance of a specialist, casing crew. Two years' field experience offshore Norway with a prototype on the semisubmersible drilling rig "Polar Pioneer", has been studied to analyse the consequences the new equipment and procedures has had for safety, costs, efficiency and the working environment.
Relative Permeability of Naturally Fractured Reservoirs from Field Performance Data
Authors: Owusu L. A. , Ershaghi I.
Published: December 2007

The estimation of relative permeabilities from field performance of naturally fractured reservoirs using the x-plot technique is considered for water-oil flow systems. A robust multi-porosity and multi-permeability numerical simulator was developed and used to perform parametric studies. Effect of interporosity flow on the composite relative permeability behavior of a naturally fractured reservoir is examined. A method is presented to estimate the degree of interporosity flow from field derived relative permeability data.
A Finite Element Model to Estimate In-Situ Stress and Fracture Toughness From a Step-Rate Test
Authors: Khattab H. A.
Published: December 2007

A numerical model to simulate step rate test (SRT) has been developed using finite element technology. This model accounts for the interaction of the fracture and the formation by coupling the fluid flow in both fracture and reservoir. Unlike the conventional models which utilize assumed values of fluid leak-off rate from the fracture into the formation, this coupled fluid flow model yields a realistic fluid leak-off rate. The model also incorporates the effects of rock mechanics on the fracture opening/closing and fracture extension and consequently, on the pressure behavior during a step rate test. This paper reviews the governing fluid flow and poroelastic equations both in the fracture and in the reservoir and also presents the associated finite element formulations. A procedure to history match the step rate test data, to estimate the horizontal in-situ stress and the fracture toughness of the reservoir rock, is also presented. This has been demonstrated by applying the procedure to actual field data.

The present work should be useful for investigating the fracturing mechanisms (opening/closing and propagation) so that a better understanding of the fracture behavior during a step rate test can be obtained. Proposed procedures also can be used to estimate both the horizontal in-situ stress and the fracture toughness of the reservoir rock.
Reservoir Description of West Sak Sands Using Well Logs
Authors: Panda M. N. , Zhang M. , Ogbe D. O. , Kamath V. A. , Sharma G. D.
Published: December 2007

The West Sak field located on the North Slope of Alaska is estimated to contain 25 billion barrels of heavy oil in place. This heavy oil of 10.5-22.5°API gravity lies at depths ranging from 2500 to 4500 feet. The reservoir temperature due to the overlying permafrost is between 45 and 100°F and therefore, the recovery of this oil will require the application of some enhanced oil recovery (EOR) process. Deployment of an appropriate EOR process for commercial production will require a detailed reservoir description. Delineation of the reservoir system, both at the microscopic and macroscopic scale, should include the depositional environment, the reservoir rock and fluid properties, and the rock-fluid property interactions.

This study presents the reservoir description of the West Sak sands. Salient reservoir properties such as the porosity, water saturation, and pay zone thickness are determined using well logs from the West Sak field. Isopach maps, subsurface correlations, and 3-D surface plots are prepared to determine the spatial variations in porosity and water saturation in the pay zones. The correlations of the Spontaneous Potential (SP), Gamma ray and resistivity traces of wells from the West Sak field are used to determine lateral and vertical gradients of the lithofacies of various horizons. The lithofacies distributions are then used to describe the depositional environment of these sands.

The results of the reservoir description study were used as EOR screening criteria and a number of EOR processes were found to be technically applicable to the West Sak field.
A Mathematical Model of Edgewater and Bottomwater Drives for Water Influx Calculations
Authors: Olarewaju J. S.
Published: December 2007

This paper presents a new water influx model that includes either edgewater drive, bottomwater drive or a combination of both. The solutions are presented graphically in form of dimensionless groups which make the solutions applicable to a wide range of systems. Using the classical superposition technique, an example application of the water influx solution to data from a waterdrive oil reservoir is presented.
Evaluation of Waste Energy Utilization for Downhole Steam Generation: Application to Alaskan Arctic Environment
Authors: Thomas A. H. , Maguire M. , Dehghani K. , Ogbe D. O.
Published: December 2007

Steamflooding and steam stimulation are the most popular methods for the recovery of heavy oil. Usually, the steam for these methods is generated at the surface. However, surface steam generation is not economically feasible in deep reservoirs due to excessive wellbore heat losses and high injection pressures.

Downhole steam generators, although still in the research stage, offer an alternative for steam injection into deep reservoirs. In a direct downhole steam generator (DHSG), air, gas and water are injected into a chamber downhole where upon combustion of the air and gas, steam is formed and forced into the reservoir. To produce the high pressure steam needed for deep reservoirs, powerful gas and air compressors are required on the surface. These air and gas compressors generate an excessive amount of waste heat. One method of utilizing the waste energy is to preheat the feed water prior to injection.

This paper presents a method for modelling the surface and wellbore thermal system of a downhole steam generator. A computer program is developed to model the energy balance in the DHSG system. The program determines the amount of waste energy available at the surface and uses this energy to preheat the injection water. This energy is balanced with energy derived from combustion in the DHSG. Effects of surface temperature, steam quality, injection pressure and wellbore configuration on waste energy and preheated water temperature are studied. The model is applied to arctic and non-arctic reservoirs. The effects of low surface temperature and the presence of permafrost were considered when the model is used in the study of downhole steam generation in arctic reservoirs.

Results from the program indicate that energy consumption can be reduced by using waste energy to preheat injection water. Wellbore configuration and climate were found to strongly influence energy consumption.
The Effect of the Presence of a Third Phase on Capillary Pressure By Centrifuge Method and CT Scanning
Authors: Dehghani K. , Bansal A. , Ogbe D. O. , Ostermann R. D.
Published: December 2007

A series of centrifuge experiments was conducted on Berea core plugs to investigate the equilibrium distribution of two and three phase systems in the drainage process. Computer - assisted - tomography (CT) scanning was used to determine the saturation distributions. In order to preserve the saturation distributions for the scan process the oil and water phases were solidified at the experiment conditions. Polyethylene glycol-1000 and a mixture of paraffin, nonadecane, and iodohexadecane were used as water and oil phase substitutes respectively. The spreading coefficient of oil on water was positive. A set of two phase experiments was conducted and the drainage capillary pressures for air-water, oil-water, and gas-water were calculated by the conventional Hassler and Brunner method. The oil water capillary pressure curve by Hassler and Brunner method was compared to the height saturation plots determined by the CT scanning of drainage process at two different centrifugal speeds. Three phase experiments consisted of drainage of mobile or residual oil by gas in the presence of mobile or connate water. The experimental results show that, the height saturation profiles generated in the two phase experiments agree with the capillary pressure data calculated by the Hassler and Brunner method.

The height-saturation profiles obtained by CT scan method in a three phase system including a spreading oil show that gas breakthrough occurs for the secondary drainage process at lower bond numbers and leakage and the drainage process will cause the production of the residual oil. These results also show that at the same gas saturation, gas-liquid capillary pressure in a three phase system is different from that obtained in two phase system.
Paraffin Chemical Treatment vs. Hot Oiling in Subsurface Hydraulic Wells
Authors: Wagner R. D.
Published: December 2007

The use of a crystal modifier to control paraffin deposition in hydraulically pumped wells in Hartzog Draw has proven successful. There are currently thirty wells, 11,000 BOPD, being treated chemically for paraffin. Before the chemical program was initiated, the wells were being treated by hot oiling. The frequency of hot oiling the wells averaged as high as three times per month. This cost, along with paraffin cleanouts with workover equipment and frequent pump repairs, caused high operating costs. Therefore, a chemical treatment program was implemented.

Data were gathered for each well before and after chemical treating. The total cost for hot oiling versus chemically treating the wells showed a savings of 20% per month. The cost of chemical has been reduced which in turn has lowered the treating costs from $.l6/bbl. initially to $.10/bbl. currently.

Some of the wells have shown production increases one to two months after chemical treating was initiated. This is due to keeping the entire system cleaner and reducing the plugging of the formation with paraffin, a result of hot oiling.

This paper will document the data collected and further impress the fact that chemical treatment of paraffin is far superior to hot oiling.