bluuebunny/crossref_metadata_2025 huggingface dataset:
Laboratory Design and Field Implementation of Microbial Profile Modification Process
Authors: Gullapalli Irene Lee , Bae Jae H. , Hejl Keith , Edwards Aimee
Published: December 2007

A microbial profile modification (MPM) process consisting of sequential injection of spores and nutrient was designed and tested for the first time in a carbonate reservoir. An 80-acre, inverted five-spot pattern located in Eunice Monument South Unit in Lea County, New Mexico, was chosen for the field trial. Injection profiles taken before and after the microbial treatment showed that the thief zones were plugged by the biofilm resulting in fluid diversion. Injection profiles also indicated that the biofilm which formed in the reservoir remained stable for more than 8 months. The results of the field trial proved the viability of the MPM technology.
A History of the Development of Rule 36
Authors: Smith J.E.
Published: December 2007

Rule 36 concerns the safe design and operation of oil and gas activities involving hydrogen sulfide. This paper reviews the engineering concepts behind the regulation and how they were applied.

Introduction

Rule 36, issued by the Railroad Commission of Texas on March 15, 1976, and put into effect on Sept. 1, 1976, is a regulation developed to assure the safe design and operation of oil and gas activities that must handle hydrogen sulfide. The application of the nile has expanded to become an industry guideline for this type of operation.

In developing the regulation, it was necessary to apply certain engineering concepts. This paper reviews these concepts and the manner in which they were applied.

Ensuring the safety of the general public is one of the highest callings of the professional engineer. Insight into the engineering criteria on which Rule 36 was based will assist the engineer in its effective application.

Development

When the Railroad Commission of Texas began developing its regulation for ensuring the public safety, it was determined that the following criteria would be considered:nature and toxicity of hydrogen sulfide,radius of exposure,specifications for materials and equipment,notification and protection of the public, andapplicability of the rule.

Smith presents the conditions that would be necessary for a public hazard to exist:there must be a leak;the leak must have volume and concentration that will cause a toxic condition;there must be a weather condition that does not cause dispersion; andthere must be a public to be exposed to the gas.

The engineering concepts used to develop Rule 36 aredetermination of the toxic effect on humans,determination of the H2S concentration in the system,determination of the escape rate,determination of the radius of exposure,determination of the area of exposure,selection of limiting radius,analysis of the phenomena of sulfide stress cracking and hydrogen phenomena of sulfide stress cracking and hydrogen embrittlement,analysis of the criteria for determining susceptibility to sulfide stress cracking,determination of means of H2S detection in atmosphere,determination of requirements for leak detection, anddetermination of the requirements of contingency planning.

Fig. 1 (from Smith 2) outlines the major H2S areas in Texas. Table 1 (from Smiths) is a general outline of Texas Rule 36.

The following discussion outlines the engineering concepts and how they were used in developing the rule.

Effect on Humans

To ensure that any potentially harmful concentration would be considered, it was necessary to determine the effect of H2S on humans Tables 2 and 3 (tom the API) present data on this effect. Based on these data, the present data on this effect. Based on these data, the 100-ppm H2S concentration was selected as the base line. The 500-ppm H2S concentration was selected as the so-called knock-down limit. The Railroad Commission hearing transcripts further support these selections. Atherton and ANSI Standard 237.2 (1968) describe the limit for effects on humans.

JPT

P. 1227
Pyrolysis of Subbituminous New Mexico Coal
Authors: Nuttall H.E. , Stoddard Wendell G. , Chen R.
Published: December 2007

Introduction

Most previous studies on devolatilization have concentrated on the effects of temperature, heating rates, and pressure. Various correlations have resulted from these studies. However, the role of particle size in the devolatilization step has not been studied thoroughly. Since a larger particle size tends to slow down heat and mass-transfer rates, the overall reaction rate will be reduced and the quality and quantity of the product gas will be affected. This study is a preliminary investigation of single-particle devolatilization using 2.5-cm diameter San Juan subbituminous coal. The apparent devolatilization-rate constant and activation energy were determined by a least-squares fit of the initial rate data. Two distinct mathematical models are presented and used to investigate the particle-temperature curve and the weight-loss history. This equipment and system are described in further detail by Stoddart.

Description of Equipment

Our experimental work centered around a bench-scale single-particle reactor, whose internal conditions could be both controlled and monitored by a minicomputer. Supporting equipment included a carrier gas flow system and product collection and analysis systems.

JPT
Fracturing With a High-Strength Proppant
Authors: Cooke Claude E.
Published: December 2007

Introduction

The shortage of natural gas in the U.S. has caused an increasing number ofdeep well completions over the past several years--a trend that will likelycontinue. Many of these deeper wells will require hydraulic fracturingtreatments in order to produce at economic rates. To achieve successfulfracturing results, a material having properties superior to sand is needed toprop open the hydraulic fractures created at the high earth stresses present indeep wells. Silica sand, the commonly used propping material, tends to crush atclosure stresses encountered in deep formations, producing fine particles orfragments that can drastically reduce fluid conductivity of the proppedfracture. propped fracture. Efforts to develop a proppant capable of bearinghigh stresses without excessive crushing have produced such materials as glassbeads, steel shot, and aluminum pellets. Glass beads have been usedcommercially for over ten years, but there is evidence indicating that thestrength of the glass in multilayers is greatly decreased in the presence ofbrine. Metallic materials are presence of brine. Metallic materials arecomparatively expensive and corrode, so their use has been very limited. Otherresearch has looked at deformable materials, such as nut shells, that will notcrush and will prop open a fracture when a partial layer is present. The use ofdeformable propping materials in partial monolayer propping materials inpartial monolayer concentrations appears to have decreased in recent years.

Exxon Production Research Company (EPR) has worked for several years todevelop improved, high-strength proppants. A wide variety of materials weretested in the laboratory under simulated reservoir conditions. One material, sintered bauxite particles, showed greatly improved properties particles, showed greatly improved properties over any material available in the past andit has been field tested to date in 12 wells--all deeper than 10,000 ft.

This paper discusses laboratory studies of the new, high-strength bauxiteproppant, describes field applications of the proppant, and summarizes factorsaffecting gas well stimulation. The field results have shown that the benefitspredicted from laboratory studies can be realized. Widespread use of the newhigh-strength proppant is expected in the future.
Productivity Correlation for Horizontal Sinks Completed in Fractured Reservoirs
Authors: Sato Kozo
Published: December 2007

When completed in fractured reservoirs, horizontal sinks (hydraulically fractured wells or horizontal wells) are believed to intersect several fractures and outperform their vertical counterparts. Based on the numerical experiment outcomes, productivity correlations are developed with horizontal-sink length and fracture parameters as the correlating parameters. The correlations are of use in predicting the expected value and the most likely minimum value of productivity for a horizontal sink parallel or perpendicular to fractures.

Analyzing the correlations developed enables us to quantify the individual contributions of a sink itself, distributed fractures, and sink-intersecting fractures to the horizontal-sink productivity. Fractures tend to yield a significantly magnified contribution to the productivity when they intersect the horizontal sink. The advantage of completing a horizontal sink perpendicular rather than parallel to fractures is attributed largely to such fractures.
Prediction of Turbulent Friction in Rod-Pumped Wells
Authors: Xu Jun , Shirazi S. A. , Doty D. R. , Prado M. G. , Blais R. N.
Published: December 2007

Frictional forces acting on a rod caused by a rod reciprocating in flowing fluid significantly affect the prediction and diagnosis of rod pumping system performance. Available studies of the flow in the tubing combined with moving rods and couplings are limited to laminar flow. The flow is more likely to be turbulent, however, for liquids with low viscosity and for regions near the rod couplings. Therefore in the current study, turbulent flow in the annular region between the stationary tubing wall and the moving rod/coupling is considered.

Computational fluid dynamics (CFD) is used to simulate turbulent flow in the annular region with moving rods and couplings. Also, a simplified model using a mixing-length method is developed that is more computationally efficient than the CFD code. The CFD code that uses the standard k–ε model is used to predict turbulent friction factors in the annulus with the moving rods and couplings. The simplified model is developed to predict turbulent friction factors in the annulus with the moving rods. The results from these models are compared with each other and to the available data published. The friction factors between the rod/coupling and fluid can be represented by four parameters: the rod to tubing radius ratio, the coupling to tubing radius ratio, the fluid Reynolds number, and the relative rod velocity.
Valuation of Gas Reserves
Authors: Davis Ralph E. , Wege J. Milton
Published: December 2007

Introduction

Much has been said and written on this subject, and of its kindred subject, the valuation of oil reserves. Little would be gained by merely quoting again that which has been said and written. Our object in this presentation is to bring out ideas and maybe methods that have not been heretofore presented, or at least have not been widely circulated in the literature of this subject.

The fundamentals of this art or science or business of appraising gas properties have been presented by many writers. To avoid the necessity of reviewing and restating the basic factors and methods frequently employed, we refer you to a fairly recent discussion by the senior author of this paper in collaboration with Eugene A. Stephenson as presented in a paper entitled "The Valuation of Natural Gas Property". "The fundamentals were then expressed as clearly as we can do it today.

In this paper we presume the understanding of the points made in the paper referred to, and address this paper to a discussion of the appraisal of "gas reserves" as distinguished from "natural gas property." Hence, we assume a "proved reserve" available for sale in the conditions that exist today - as to financial, economic and political influences.

Generally speaking, properties such as gas properties are worth more money - i.e., they will sell for more money - when the financial conditions of the country and of the industry are good, when it is easier to finance. Also it is true that such a property is worth more money when the economic conditions are good, such as a continuing increase of the demand for the product and no serious threat of a cheaper competitive fuel; and also such a property is worth more money if the political atmosphere is favorable. The fixing of price, or even the threat of the fixing of price, by government, lessens the desirability of the property whose product is regulated. These factors should, we believe, be taken into consideration by the appraiser.
Numerical Homogenization of the Absolute Permeability Tensor Around a Well
Authors: Wouter Zijl , Trykozko Anna
Published: December 2007

This paper presents an extension of the classical homogenization method of upscaling around a well. The use of homogenization theory has been made possible by a transform of the cylindrical homogenization cell around a well to an "equivalent rectangular cell."

First, it is shown by an introductory example for radial flow that direct use of the original homogenization cell leads to more than one coarse-scale permeability. This is at variance with the approach based on the transform to an equivalent rectangular cell, which yields one unique coarse-scale permeability that can be applied consistently both in Darcy's law and in the dissipation equation.

The main body of the paper describes the extension of this transformational approach to general 3D permeability tensors, without assuming purely radial flow. The pressure equation is solved numerically; from this solution, classical homogenization algorithms compute the "transformed homogenized permeability tensor" in the equivalent rectangular cell.

Finally, a back transform to the original homogenization cell leads to the coarse-scale permeability tensor. Validation examples compare the numerical homogenization with global upscaling.
Applications of Engineering Valuations in Management
Authors: Reistle C.E.
Published: December 2007

Introduction

One of the most important decisions which the management of a corporation is called upon to make involves the investment of company funds to produce maximum benefit for the stockholders. Generally, this is not a one-time decision which can be made and then forgotten, as new funds are constantly being generated which require investment; and new investment opportunities are developing which require funds. In arriving at these investment decisions and in balancing the flow of earnings with the opportunities for investment, the valuation of the proposed investment represents the basic data which are available in management. In a producing company, this valuation is generally of an engineering type.

The engineering valuation should encompass every phase of a company's operation. It should provide the information with which management can measure and compare new investments but also should measure existing investments and operations. Management depends to a very large degree upon their technical staffs for new ideas and new opportunities, both in investments and in improving the return on existing investments through improved operation.

Even the simplest type of engineering valuation requires consideration of a multitude of factors. Extremely complex is valuation of new construction in which the income resulting from the investment is related to the operation and income of a number of facilities. But management must have valuations to act as guides at each step in the road. In construction, not only must the physical equipment be properly selected, but the size must be chosen to strike a proper balance between rate of income and initial investment. The effect of the new construction on the income of existing or anticipated other equipment must be analyzed and included in the valuation.

Investments and Engineering Valuations

From this discussion, it can be seen that the management of any profit-conscious corporation must lean heavily upon engineering valuations in arriving at decisions on all types of investments. The very large number of points which must be included serves to emphasize the importance of and the reliance placed upon a proper valuation. But there is also one factor which should not be included. That is the safety factor.
Gas Slippage and Permeability Measurements
Authors: Estes Robert K. , Fulton Paul F.
Published: December 2007

Introduction

Relative permeabilities are factual data necessary to any prediction of reservoir production behavior. One important problem in determining relative permeabilities of porous media to gas is the effect of gas slippage on these determinations. Since certain aspects of the slippage phenomenon still remain unknown, this study is particularly concerned with that problem.

The validity of the theory of gas slippage as it is applied to the flow of gas through porous media has been well established. Therefore, in determining the permeabilities of porous media to gas by ordinary laboratory procedure, i.e., at atmospheric pressure, the slippage correction should be considered. Rose performed experiments on gas relative permeabilities which indicated that the effect of gas slippage on the measured effective gas permeabilities at various liquid saturations decreased with an increase in liquid saturation.

Following Rose, it was substantiated experimentally that the effective gas permeabilities at the various liquid saturations extrapolated to infinite mean pressure were the same as the non-wetting liquid permeabilities at the same saturations. This same paper also presented data which showed that the magnitude of the slippage between those values of gas effective permeability determined at atmospheric pressure and those found by extrapolation to infinite mean pressure decreased with an increase in liquid saturation. However, these experiments were not performed at liquid saturations above 30 per cent. Therefore, the purpose of this experimental work was to determine the effect of gas slippage on permeability measurements at liquid saturations in excess of 30 per cent.

Apparatus

Five core samples were used in this work: two synthetic Alundum samples (A-1, and A-2), a Nichols Buff sandstone sample (NB-13), and two samples from producing formations, a Soso sandstone (S-1), and a vugular dolomitic limestone (R-7). The core samples ranged in permeability from 32 to 663 md. These cores were chosen because they represented a fairly wide range of permeabilities and probably a considerable difference in pore size and pore size distribution.
Adverse Effects of Poor Mudcake Quality: A Supercharging and Fluid Sampling Study
Authors: Sarkar Amit K. , Lee Jaedong , Kasap Ekrem
Published: December 2007

Wireline formation testers are routinely used at discrete depths of a well to collect reservoir fluid samples and to estimate undisturbed reservoir pressures, near-wellbore formation permeabilities, fluid compressibilities, and saturation pressures. A pressure profile in the vertical direction yields fluid densities and fluid contacts (gas/oil and water/oil contacts) in the reservoir. Reliable results are obtained when the mudcake isolates the wellbore from the formation. When the mudcake cannot provide isolation, mud filtrate invasion continues and supercharging occurs. The issue of sample quality becomes critical when using oil-based muds because the filtrate is also oil and is difficult to separate from the formation oil, a pure sample of which is needed for fluid characterization studies. This study investigated the effects of poor mudcake seal on sample quality and formation test data and its analysis when oil-based muds are used. Modeling studies were conducted using a finite-element simulator.

The results of the study indicate that mudcake permeabilities must be less than 1 μd and mudcake-to-formation permeability ratios must be less than 10−4 to achieve sample qualities higher than 90%. Such conditions as high pumpout rates, low overbalance pressures, and shallow filtrate invasion depths improve sample quality. The presence of a permeability-damaged zone around the mudcake improves the sample quality but reduces the sampling pressure. The formation rate analysis (FRASM)† technique estimates formation permeability accurately in the presence or absence of supercharging. The formation pressure estimated using the buildup data is the pressure at the mudcake-formation interface. The supercharged pressure must be subtracted from the apparent formation pressure to obtain the true formation pressure. A simple procedure is developed for estimating the mudcake permeability and the supercharged pressure. Supercharged pressure is shown to be a product of the apparent overbalance pressure, mudcake-to-formation permeability ratio, and an invasion factor representing the distance up to which supercharging extends.
Effects of Polymer Adsorption and Flow Behavior on Two-Phase Flow in Porous Media
Authors: Zheng C. G. , Gall B. L. , Gao H. W. , Miller A. E. , Bryant R. S.
Published: December 2007

To determine the effect of water-soluble polyacrylamide polymer adsorption and flow behavior on oil recovery, relative permeability and mobility were determined from flow experiments at various polymer concentrations. A selective reduction of the relative permeability to water with respect to the relative permeability to oil was observed for both Berea and reservoir sandstone cores. Adsorbed polymer layer increases water wettability. Relative permeability reduction could be attributed to both wettability change and pore-size restriction due to the adsorbed polymer layer. An empirical model was proposed to correlate the relative permeability reduction and the amount of polymer adsorption. Depletion-layer effect results in a reduced polymer viscosity in porous media with respect to bulk solutions. Modification of the existing shear-rate model allows for accurate prediction of this effect. The integration of the new models in UTCHEM provides a more accurate tool for engineering design of polymer applications.
Simplified Phase-Equilibrium Calculations in Integrated Reservoir and Surface-Pipeline-Network Models
Authors: Litvak M. L. , Wang C. H.
Published: December 2007

Effective procedures for the integrated reservoir and surface facility compositional simulations have been developed. Multiphase compositional fluid flow equations in reservoirs, well tubing strings, and surface pipeline network systems are solved simultaneously. The procedures have been implemented in the commercial compositional reservoir and surface facility simulator: VIP.

The equation of state is applied for the phase-equilibrium calculations. A new equation-of-state (EOS) interpolation procedure has been developed (as an option) for simplified phase-equilibrium calculations in integrated compositional simulations. The EOS interpolation procedure can be effectively applied for phase-equilibrium calculations in reservoirs, well tubing strings, pipelines, and/or separators. Saturation pressure, recovery factors of hydrocarbon components, and compressibility factors are determined as tabular functions of pressure, temperature, and fluid compositions. The equation of state is applied for the automatic generation of these functions in an initialization step of a reservoir simulation.

The effectiveness and accuracy of the new simplified phase-equilibrium procedure have been confirmed in many full-field compositional models and pattern models. The new option significantly reduces the central processing unit time required for the simulations and it matches results of fully compositional simulations in the tested models.

The developed procedures for the integrated reservoir and facility compositional simulations have been applied in many reservoir studies. Their applications in the integrated reservoir and surface facility model of the giant Prudhoe Bay oil field have been demonstrated.
Development of Sycamore Sandstone Sholom Alechem Field, Stephens and Carter Counties, Oklahoma
Authors: Clark N.E. , Wall L.J.
Published: December 2007

This paper covers various drilling problems and completion techniques in the 9,000-acre Sholom Alechem field of Stephens and Carter counties, Oklahoma. Oil and gas production is from the Sycamore formation at 8,000 ft deep. Although normally a limestone, this Mississippian age reservoir is a calcareous sandstone at Sholom Alechem.

Introduction

The cumulative crude oil production per acre or per acre-foot in Stephens and Carter counties is as great as any other sizeable area in Oklahoma. Recent Sycamore sandstone development in a previously neglected formation, the Sholom Alechem field of Stephens and Carter counties (Fig. 1), has added significantly to this cumulative production. production. The Sholom Alechem field (Fig. 2) is located in the eastern half of Township 1 South, Range 4 West, and Township 1 North, Range 4 West, Stephens County, and in the western part of Township 1 South, Range 3 West, Carter County. The Sycamore sandstone development, begun in 1972, includes 110 wells on an 80-acre spacing, involves 26 operators, and essentially has been completed. The Sycamore formation is found from 7,500 to 8,200 ft. Current daily production is 3,100 bbl and a total of 6,860,000 bbl has been produced from the Sycamore as of Oct. 31, 1976.

Ultimate production is expected to range from 10 to 12 million bbl of oil and 75 million Mcf of casinghead gas.

History

Oil originally was found in this area by Humble Oil and Refining Co. in 1923. The discovery well was the Jennings No. 1, located in the SW SW of Section 28-T1S-R3W, Carter County. The producing formation was the Pennsylvanian Deese sand at 3,400 ft. Early development was slow because the wells were low-volume producers and remained slow in the 1930's and 1940's, producers and remained slow in the 1930's and 1940's, because of the Depression and World War II. In Aug. 1947, Stanolind Oil and Gas Co. discovered Springer sand in their Sims No. 1 located in the NE SE of Section 2-T1S-R4W, Stephens County. The well produced 118 B/D of low-gravity oil from 4,800 ft. Rapid development continued for the next 5 years, with additional Deese and Springer sands discovered and developed. Much of this development was done on a 10-acre spacing. During the next 15 years, shallow development was limited to drilling a few edge and infill wells, plus beginning several secondary recovery projects, primarily waterfloods of the Sims and Deese projects, primarily waterfloods of the Sims and Deese sands.

JPT

P. 35
An Evaluation of the Robertson-Stiff Model Describing Rheological Properties of Drilling Fluids and Cement Slurries
Authors: Beirute R.M. , Flumerfelt R.W.
Published: December 2007

This paper evaluates the Robertson-Stiff rheological model for cement slurries and drilling muds. The model is compared with the Herschel-Bulkley model and is found to be an improved model for cement slurries. The Robertson-Stiff equations for volumetric flow rates in narrow annuli and tubes are shown to be limited to fluids with no yield stress. This paper develops more general equations that include the Robertson-Stiff results as special cases.

Introduction

In a recent paper, Robertson and Stiff presented a new model for describing the rheological behavior of drilling fluids and cement slurries. The principal advantages claimed for this model areit provides better fits of rheological data than other three-constant viscous models, andit gives explicit relations for the velocity fields, wall shear rates, and flow-rate/pressure-drop relations for flow in tubes and annuli.

The latter advantage is not possible with comparable models such as the possible with comparable models such as the Herschel-Bulkley model. In this paper we provide an independent evaluation of the model with regard to these characteristics.

First, we checked the accuracy of the model in fitting cement-slurry data and found that it does provide a good match to the experimental data. Fig. provide a good match to the experimental data. Fig. 1 shows the experimental data for a cement slurry along with fitting curves for the Robertson-Stiff and Herschel-Bulkley models. It can be seen that the Robertson-Stiff model is somewhat superior to the Herschel-Bulkley model in representing the data. This is also true in Fig. 2, which represents results for a different cement slurry of higher yield. Here again, the performance of the Robertson-Stiff model is somewhat better. Based on these observations, as well as others not presented here, we agree with the authors that their model is an improved model for cement slurries.

With regard to the claim that the model provides explicit relations for the wall shear rate and pressure-drop/flow-rate relation, we have found pressure-drop/flow-rate relation, we have found certain errors in the Robertson-Stiff analysis that invalidate this claim and make their final equations applicable only in certain special cases.

The basic error in their paper is that Robertson and Stiff overlooked the existence of a plug flow region in the center of the pipe or narrow annulus. Because of this, the equations derived are strictly valid only for the case of fluids with zero yield stress. Since most drilling fluids and cement slurries show some finite yield stress, the equations provided by Robertson and Stiff are of limited provided by Robertson and Stiff are of limited application. In the remainder of this paper we derive the correct relations for the model; the Robertson-Stiff relations appear as special cases.

SPEJ

P. 97
Fluid/Rock Interactions Between Xanthan/Chromium(III) Gel Systems and Dolomite Core Material
Authors: McCool C. S. , Green D. W. , Willhite G. P.
Published: December 2007

Gelation of chromium(III)/xanthan systems in dolomite core material for in-depth matrix rock treatments was investigated. The gels contained approximately 2,000 ppm xanthan and the dolomite core material was obtained from a San Andres dolomite reservoir in Texas and had permeabilities ranging from 4 to 10 md. Compositional changes in the gelant caused by interactions with the dolomite core material resulted in small permeability reductions for gelants prepared with chromium chloride, chromium acetate and a chromium diamine salt. The primary cause of incomplete gelation in the dolomite material was attributed to the increase in gelant pH that resulted in precipitation of chromium.
Modeling and Optimizing Oil and Gas Production and Gathering Systems: Cerro Fortunoso Field Case
Authors: Galliano G. R. , Degiorgis G. L. , Lopez M. L. , Fornes Adriana
Published: December 2007

Cerro Fortunoso field produces a heavy and viscous oil and a separator gas which contains 95% of CO2. In 1996 a decision was made to reinject the gas to maintain pressure and prevent environmental damage. A technical team used a network simulator to model both the current oil gathering and the future gas reinjection systems. A parallel study was conducted to analyze the effect of non-Newtonian performance on predicted pressure drop. Although deviation was found to be slight, the non-Newtonian effect should be properly included in design calculations. Besides, as the gas will be reinjected near its critical point, thermodynamics becomes extremely important.
Modeling Nonlinear Interactions Among Near-Well Flow Restrictions in Well-Deliverability Prediction and Simulation
Authors: Hwang M. K.
Published: December 2007

This work describes simulation of well productivity reduction due to near-well flow restrictions. The flow restrictions considered include: mechanical skin, partial completion, altered formation due to residual completion fluid or liquid dropout, and non-Darcy flow effects. It addresses two specific issues. The first is how to predict changes in well performance induced by changes in near-well parameters, as needed in history matching and well test analysis. A subset of this issue is how to estimate the impact of using well parameters to simplify simulation models such as partial completion skin and non-Darcy flow skin, instead of using more layers and solving the non-Darcy flow equation. The second issue is how to accurately preserve well productivity in a large grid block, as in the case of well productivity reduced by liquid dropout in a gas condensate reservoir model.

To resolve these issues, this work uses direct simulation and heuristic total skin equations developed for one-dimensional and two-dimensional multilayered cases with crossflow. The equation correctly represents the effects of nonlinear interactions among near-well flow restrictions on well productivity, resulting in an effective total skin that is much larger than the conventional linear sum of individual skin components. Numerical examples show the total skin equation can be used to predict well performance and to accurately preserve well productivity in a field-scale gas condensate reservoir model. The latter use of the equation shows a feedback mechanism, wherein the total skin is used to adjust the coarse-grid well productivity.
Fluid Placement Model for Horizontal-Well Stimulation
Authors: Eckerfield L. D. , Zhu D. , Hill A. D. , Robert J. A. , Bartko K. M.
Published: December 2007

Acidizing is a common method used to stimulate horizontal wells. The acidizing process is fundamentally different when applied in a horizontal well compared with application in a vertical well. The fluid distribution in a horizontal well is affected by a longer wellbore length, a broader variation in the reservoir properties along the wellbore, and possibly different mechanical means by which to place the fluids in the wellbore. A comprehensive fluid placement model linked with a reservoir acidizing simulator is essential to precisely design acidizing treatments for horizontal wells.

In this paper we present a model of fluid placement in a horizontal well. The model predicts the placement of injected fluids by tracking the interfaces of different fluids in the wellbore. It is capable of tracking multiple interfaces for multiple injection stages in horizontal wells. For injection with coiled tubing, the model allows tubing tail movement during injection. It also handles simultaneous injection from the annulus and from a tubing string. The fluid distribution generated from the model can be used as input information in a reservoir acidizing model for sand-stone acidizing design. Both analytical and discretized solutions of the model are presented in the paper. Examples in the paper illustrate the effects of such factors as velocity of tubing movement, annular injection, and a nonuniform distribution of flow into the reservoir on fluid placement in an acidizing treatment.

The fluid placement model can help to determine optimum tubing tail locations and optimal injection volumes of acids, to select the most appropriate diverting methods, and, hence, to maximize the benefits of an acidizing treatment.
Reservoir Characterization Constrained to Well-Test Data: A Field Example
Authors: Landa J. L. , Horne R. N. , Kamal M. M. , Jenkins C. D.
Published: December 2007

In this paper we present a method to integrate well test, production, shut-in pressure, log, core, and geological data to obtain a reservoir description for the Pagerungan field, offshore Indonesia. The method computes spatial distributions of permeability and porosity and generates a pressure response for comparison to field data. This technique produced a good match with well-test data from three wells and seven shut-in pressures. The permeability and porosity distributions also provide a reasonable explanation of the observed effects of a nearby aquifer on individual wells. As a final step, the method is compared to an alternate technique (object modeling) that models the reservoir as a two-dimensional channel.
Successful Drilling Practices: An Experiment in Cooperation
Authors: Brett J. F. , Gregoli M. K. , Gahan B. C.
Published: December 2007

This paper presents the results of a Gas Research Institute funded study to test the following hypothesis:

"Broad-based benefit is created when drilling organizations systematically cooperate to identify and share successful practices"

To this end, 11 separate successful drilling practices studies (SDP) were commissioned with the following goals: identify the most successful drilling practices for each of the study areas; document these practices in enough detail (in the form of a complete drilling operations plan) to ensure practical application; disseminate the successful practices; and measure the benefit derived from using the successful drilling operations plans.

The studies focus on the following 11 drilling environments:

Greater Green River basin (two studies: South Moxa arch Dakota formation and Wamsutter Almond formation), Arkoma Basin (two studies: Choctaw thrust and Jackfork plays), Cotton Valley Reef play in east Texas, Deep Austin chalk (Texas), Valverde basin (Straw and Penn sands, Texas), Anadarko basin (Watonga-Chickasha trend Morrow/Springer formations), South Texas Gulf coast (Wilcox Lobo trend), Deepwater (Green Canyon area), and Extended-reach (South Pass area) drilling in the Gulf of Mexico.

This paper outlines the methodology used to develop these SDP studies, and the benefits reported by operators who have used them. Evidence presented shows that broad-based benefit can be created when drilling organizations systematically cooperate to identify and share successful practices, and that the benefit ranges from 3 to 20% of total drilling costs, with an average benefit on the order of 10%.
Effects of Grid Systems on Predicting Horizontal-Well Productivity
Authors: Wan Jing , Penmatcha V. R. , Arbabi Sepehr , Aziz Khalid
Published: December 2007

We compare horizontal-well performance for different grid types using a conventional formula for the well index. These results are also compared with the results of explicit well modeling, which does not require a well index. To assess the accuracy of numerical solutions, examples chosen are those for which exact analytical solutions are also available. These analytical solutions are for horizontal wells in brick-shaped homogeneous (isotropic or aniso-tropic) reservoirs (or drainage volumes). When a horizontal well extends through the full length of the reservoir, the problem be-comes two-dimensional with uniform influx along the well. On the other hand, if the well is completed in only a part of the reservoir (partially penetrating) a three-dimensional (3D) solution is needed. The 3D solution also predicts the influx profile along the well, with higher influx at the two ends. Because the conventional well index calculation does not account for the 3D nature of flow, the flow rate of the well may be incorrect. We have found that the well index obtained with the default procedure in most simulators (Peaceman's method) needs to be increased for the numerical simulator to predict the productivity of horizontal wells correctly.

The correct well index can be obtained for any well if a suitable analytical solution is available. When such solutions are not avail-able, reference solutions can also be obtained by explicitly mod-eling the well with blocks that are of the same size as the well. In this case, there is no need for a well index. However, our analysis shows that for correct results the grid-aspect ratio for blocks rep-resenting the well and surrounding blocks has to be close to 1.
Effect of Gas Enrichment Above the MME on Oil Recovery in Enriched-Gas Floods
Authors: Johns R. T. , Sah Pashupati , Subramanian S. K.
Published: December 2007

The interaction of phase behavior and flow, in the presence of dispersive mixing, is examined for one-dimensional four-component enriched-gas displacements. Numerical and analytical solutions demonstrate that oil recovery may be substantially increased by gas enrichment above the minimum enrichment for miscibility (MME). The level of increase is dependent on the level of dispersive mixing and the size and shape of the two-phase region.

A critical gas enrichment (CGE) above the MME is defined that separates the multicontact miscibility (MCM) region into two regions: MCM1, when the gas lies within the region of tie-line extensions, and MCM2, when the gas lies outside. For enrichments below the CGE (in MCM1), oil recovery can increase significantly with enrichment. Above the CGE (in MCM2), oil recovery is not as sensitive to enrichment for the cases studied. Displacements in the MCM1 region exhibit a combined condensing and vaporizing mechanism, whereas displacements in the MCM2 region are purely condensing.
Behavior and Effect of SARA Fractions of Oil During Combustion
Authors: Kok M. V. , Karacan C. O.
Published: December 2007

In this study, saturate, aromatic, resin, and asphaltene fractions of two Turkish crude oils (medium and heavy) were separated by column chromatographic techniques. Combustion experiments were performed on whole oils and fractions by a thermogravimetric analyzer (TG/DTG) and differential scanning calorimeter (DSC) by using air and a 10°C/min heating rate. TG and DSC data were analyzed for the determination of weight loss due to possible reactions, and for reaction enthalpies of individual fractions, which have to be known for in-situ combustion technology utilization.
In-Situ Rheological Characterization of Drilling Mud
Authors: Maglione Roberto , Robotti Giovanni , Romagnoli Raffaele
Published: December 2007

The rheological model of Herschel and Bulkley reported in 1926 can be applied to determine the characteristic parameters of a drilling fluid. In this paper, an in-situ characterization approach is proposed.

During flow tests at fixed drilling depths inside the well the pump rates and the relative stand pipe pressures (SPP's) are recorded. This allows one to determine in-situ the Herschel and Bulkley rheological parameters and the behavior of the drilling mud circulating in the well.

The results are compared to those obtained in the laboratory using a Fann VG 35 viscometer for the same drilling mud. It is found that the rheological triad from the viscometer data does not always coincide with the rheological triad from the in-situ drilling test. Thus, the calculated SPP using viscometer readings could lead to misleading errors for an actual process. This method could be useful not only to calculate and predict the SPP, but also to evaluate with accuracy the annular pressure drop in order to obtain the maximum allowable pump rates without fracturing the formations.

We discuss the sensitivity of the results in relation to the equivalent viscosity of the drilling fluids considered to some of the main practical drilling parameters, such as the flow velocity and pressure spatial distribution along the wellbore profile and, with reference to the mud structure, sensitivity to pressure and temperature.

Considering the drilling well essentially as a viscometer (WAV) enables one to investigate the performance of the drilling hydraulic circuit and also the effects of the true effective viscosity (here called equivalent viscosity) and of the rheological behavior of the muds in all types of wells, and overall in deep wells with great accuracy.
A General Correlation for Predicting the Hydrate-Free Zone of Reservoir Fluids
Authors: Østergaard K. K. , Tohidi B. , Danesh A. , Todd A. C. , Burgass R. W.
Published: December 2007

A new correlation for predicting the hydrate-free zone of reservoir fluids, from black oil to lean natural gas, has been developed. The method correlates the hydrate dissociation pressure against the specific gravity and the concentration of the hydrate-forming components in the fluid, as well as the temperature of the system. The effect of nitrogen and carbon dioxide on the hydrate-free zone has also been taken into account. The correlation has been developed using hydrate phase boundaries for 31 fluids generated by a well-proven comprehensive thermodynamic model. Hydrate phase boundaries for 13 independent reservoir fluids calculated by the new correlation and the thermodynamic model have been compared, showing a maximum error of 1.0 K in the calculated potential hydrate-forming temperature.
A Study of Two-Phase, Non-Darcy Gas Flow Through Proppant Pacs
Authors: Jin L. , Penny G. S.
Published: December 2007

Through a systematic experimental study it is found that the effect of liquid phase on non-Darcy gas flow through proppant packs cannot be characterized by Forchheimer correlation alone. An empirical equation that uses liquid-to-gas ratio to predict the effective permeability or conductivity of a proppant pack under two-phase, non-Darcy flow conditions is proposed in the paper. The effective permeability of a proppant pack at different conditions can then be calculated taking both non-Darcy and two-phase flow effect into account. A simplified physical model is developed to calculate a mobile liquid saturation at two-phase flow conditions.
Scale Dissolver Application: Production Enhancement and Formation-Damage Potential
Authors: Jordan M. M. , Graham G. M. , Sorbie K. S. , Matharu A. , Tomlins R. , Bunney J.
Published: December 2007

Sulfate scale dissolvers have been applied downhole for many years to remove barium and mixed sulfate scale deposits from the wellbore and from the near-wellbore formation. As well as dissolving mineral scales, these corrosive materials also have the potential to cause some degree of formation damage by the dissolution of reservoir minerals. In this study, three commercial scale dissolver formulations and two laboratory prepared amino car-boxylic acid dissolvers (EDTA and DTPA) were tested to assess their comparative capacity to dissolve barium sulfate and, of more importance in the current study, their potential to cause damage in the near-wellbore formation. The potential formation damage capacity of various scale dissolvers has been assessed by measuring the levels of cation release in static tests on mineral separates and by studying the various effluent profiles from core floods using reservoir sand. Possible damage mechanisms include silicate dissolution, fines generation/migration, mechanical strength reduction and wettability changes. We conclude that, when testing sulfate scale dissolvers for field application, their formation damage potential should be assessed as well as their barite dissolution performance.
Application of Engineering Effort Through Use of Reservoir Analyzers
Authors: Montague K.E. , Noble M.D. , Buchanan F.E.
Published: December 2007

This paper contains a review of the position which the reservoir engineer occupies in the industry today. His work is found to be that of collecting, assembling and analytically treating large quantities of basic data to the end that physical and economic results are optimized.

The need for methods to simplify and speed the data collecting and analytical processes of reservoir engineering is discussed. An organization utilized by one company to speed these processes is described.

A general discussion of the use of analog computers and the result of six years' experience with this approach is given. It has been found that the reservoir engineer can quickly and easily adjust himself to the use of computers as a routine part of the solution to the over-all problem. In so doing, the burden of manual computation and data processing has been considerably lightened, thereby allowing him to devote more time to original and creative work in planning the basic approach and executing and applying economics to the end result.

The Problem

The industry has long recognized the intricate complexities of the business called reservoir engineering. The application of the fundamental principles established to date has resulted in a large accumulation of raw data from drilling production and laboratory operations. A normal development program yields voluminous records of electric logging, core analysis, drilling data, laboratory analyses of gas, oil and water, reservoir production of gas, oil and water, reservoir pressures, gas plant reports, etc. The engineer must analyze this information and blend it into the complex array of conservation rules and regulations and general cost and profit economics in order to design the most economic oil recovery process. Faced with this duty, the engineer must find time to perform it responsibly. Routine work must be minimized as much as possible.