bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Reservoir Management with Water Quality Enhancement at the North Robertson Unit
Authors: Nevans J. W. , Pande P. K. , Clark M. B.
Published: December 2007

The quality of injection waters used in any new or existing waterflood or EOR ·process should be considered as a critical component of reservoir management and surveillance programs. Despite decades of industry experience with recovery processes utilizing water in the Permian Basin (and most other major oil producing basins of the world), water quality is an often neglected aspect of reservoir management programs. Consequently, severe injectivity and operational problems are frequently experienced.

This paper describes a case study of water quality control for the Clearfork and Glorieta reservoirs (Permian age) of the North Robertson Unit (NRU) located in the Permian Basin of West Texas. A cost-effective surveillance program for the timely identification and treatment of potential water quality control problems has been designed and implemented. Integration of geological and reservoir parameters, which are crucial to ensure the realization of optimal reservoir performance and operational objectives, is highlighted.
Transient Well Testing of Coalbed Methane Reservoirs with Horizontal Wells
Authors: Sarkar P. S. , Rajtar J. M.
Published: December 2007

Natural gas production from coalbeds using horizontal wells may be of interest to producers in the future. Since sedimentary gas reserves are limited, the unconventional gas reservoirs could be an alternative resource to meet the demand for natural gas. Naturally fractured coalbeds with their dual porosity character can produce at much higher rates with horizontal wells. The presented paper shows an analytical solution for transient pressure response of a horizontal well in a coalbed reservoir. Effects of wellbore storage and skin on the solution are illustrated. The solution is developed for a semi-infinite, anisotropic coalbed reservoir assuming single phase gas flow. The solution can be used to generate type curves for particular reservoir geometry and subsequent determination of reservoir parameters.

The paper illustrates the application of type curve matching for a typical case through an example on computer generated data.
Pregel Blender Prototype Designed To Reduce Cost and Environmental Problems
Authors: Allen T. E.
Published: December 2007

A new pregel blender is being developed to continuously mix dry gel on the fly for fracturing treatments. Specifically, this system can either continuously mix dry gel at the job concentra-tion the operator selects, or mix a liquid concentrate that is later diluted to the required final job concentration. A holding tank is provided to hydrate gels for both modes of operation.

The proposed system has several major economic and environ-mental advantages over previously designed preblenders. Not only should it provide a gel quality comparable to a liquid gel concentrate (LGC), but it will not require diesel and/or the other chemicals required to make LGCs. As a result, the system should save time and expense over LGC processes and conven-tional batch-mixing, while being safe to use in environmentally sensitive areas.
Hydraulic Fracturing of the Multizone Wells in the Pegasus (Devonian) Field, West Texas
Authors: Olson K. E. , El-Rabaa A. W. M.
Published: December 2007

A large developmental program in the Pegasus (Devonian) field commenced in early 1990. The program triggered a completion optimization process aimed at effectively stimulating the Pegasus wells, as well as reducing cost. Elements of optimization included are the field and laboratory data gathering efforts, the integration of data into the stimulation design, and the field and laboratory diagnostics. The completion costs were reduced by more than 40%, which translated into 20% savings in the overall well cost.
The New, Generalized Material Balance as an Equation of a Straight Line: Part 2 – Applications to Saturated and Non-Volumetric Reservoirs
Authors: Walsh M. P. , Ansah Joseph , Raghavan Rajagopoal
Published: December 2007

This paper is the second in a two-part series of papers which features practical applications of the generalized material-balance equation. Applications to initially-saturated and non-volumetric reservoirs are discussed in this paper (Part 2); applications to initially-undersaturated, volumetric reservoirs are discussed in Part 1. Graphical methods to estimate the original oil and gas in-place are presented. The graphical methods are general and are applicable to the full range of reservoir fluids of interest. Example calculations are carried out for gas-cap and water-influx reservoirs. These examples, along with those discussed in Part 1, demonstrate the extraordinary power of the generalized material-balance equation.*
Laboratory Study on Surfactant-Based Selective Mobility Control
Authors: Dixit Amulya , Tsau Jyun S. , Heller John P.
Published: December 2007

Carbon dioxide flooding has been recognized as an efficient means of recovering oil. However, the efficiency is marred due to the unfavorable mobility ratio between CO2 and the oil to be displaced and die poor sweep efficiency resulting from the heterogeneity of the reservoir. The goals of this study are to develop a quick and efficient method to explore the possible application of foam in mobility control, and to identify available surfactant in such an application to increase the sweep efficiency, and therefore the oil recovery. Some of the results from this study show that mobility of CO2 is significantly reduced by using the foam. In addition to that, a possible characteristic of foam in selective mobility reduction (SMR) is also observed in some of the tests in which the CO2-foam mobility was found to be lower in higher permeability rock samples than that in lower permeability rock samples. In other words, the flow of foam is likely less mobile in a more permeable porous media than that in a less permeable region of the reservoir formation. This behavior is favorable to preserve the uniformity of a flood front as it propagates through the rocks with nonuniform permeability. Based on limited data, however, the SMR is found to be dependent on flow rate and on the type of rocks when using the same surfactant.
A New Pre-Production Well Test for Analysis of Multilayered Commingled Reservoirs With Unequal Initial Pressures
Authors: Aly Ahmed , Lee W. J.
Published: December 2007

The main objective of this paper is to design a new well test that will unable us to determine the individual layer properties (layer permeability, layer porosity, layer diffusivity and layer skin) early in the life of the reservoir, taking into considerations cost, time and the environmental impact of well testing. The pre-production well test is a well test that is carried early in the life of the reservoirs when the information is most needed for planning production schedule and economic decisions concerning the life of the wells. Pre-production is the period after completion but before production of the well. Directly after perforations, we position a pressure gauge above the top perforation to measure the pressure performance from the total system (two or three layer systems). Cross flow in the wellbore from one layer to another will cause the pressure signal. The cross flow is due to the differential pressure between the layers. One important advantage of the pre-production well test is that there is no production on surface during the test. Thus, the environmental impact caused by flaring oil or gas during a conventional well test is all eviated.

In this paper we developed a general mathematical solution to model the reservoir performance of commingled reservoirs with unequal initial pressures in Laplace space. The reservoir performance information available from this model includes wellbore pressures, layer sandface flowrates and layer cumulative production.

The computational solutions developed are used to model the reservoir performance for two layered and three layered cases from the literature. The results are verified by comparing them to the results generated using a finite-difference simulator. The agreement was found to be excellent for all the tested cases.

We developed the "Derivative Extreme Method" (DEM) for the analysis of the wellbore pressure measured during the pre-production well test. The DEM determines layer properties from early and middle time region data. Thus, well testing time is reduced.
Compositional Simulation of Carbonated Waterfloods in Naturally Fractured Reservoirs
Authors: Shenawi S.H. , Wu C.H.
Published: December 2007

SPE Members

This paper presents a compositional simulation of imbibition carbonated waterfloods in naturally-fractured reservoirs using a 3-dimensional, 3-phase, dual-porosity, compositional simulator (COMABS). The simulator is developed as a part of multi-disciplinary study to improve the oil recovery from low-permeability, naturally-fractured reservoirs such as Austin chalk trend. Laboratory imbibition carbonated waterfloods data using chalk cores are available for this study. The COMABS allows the partitioning of CO2 from the injected water phase into the oil phase based upon the CO2 solubility in each phase. The partitioning of CO2 is assumed to reduce oil phase viscosity and increases oil density; the transmissibilities are updated as a function of CO2 concentration.

Two grid systems are used in a cross-sectional, dual-porosity modeling of the laboratory tests. For simplicity, three dual-porosity gridblocks are used to represent the laboratory laboratory flow test systems. The carbonated water imbibes into the matrix blocks and causes the counter-current flow of oil from the matrix to the fracture. Then, fifteen dual-porosity gridblocks are used. In this system, a higher fracture permeability value is assigned for the gridblocks corresponding to the fracture in the laboratory flow test system. The simulator is capable of matching the laboratory imbibition oil recoveries. The effect of the carbonation of injected water on oil recoveries are examined with computed oil saturation, oil viscosity, oil density and CO2 concentration distributions.

A hypothetical two-dimensional field imbibition carbonated waterflood is used to demonstrate the use of COMABS for field-scale applications. The application of the simulator for field-scale imbibition carbonated waterflood may provide some insights on the impacts of imbibition and compositional variation on imbibition CO2-enriched waterflood recovery.

Introduction

The average conventional waterflood oil recovery from low-permeability, naturally-fractured reservoirs is low because the injected water may preferentially channel through the highly interconnected fractures. In the process, a portion of the injected water will imbibe into the tight rock matrix due to capillary forces and expels the oil from the matrix into the fracture. Injected water then displaces the expelled oil through the network of fractures to the producing wells.

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Use of Simulators in the Design of an Experiment for Steam Injection into a Fractured System
Authors: Sumnu M. D. , Aziz Khalid , Brigham W. E. , Castanier L. M.
Published: December 2007

To simulate steam injection in fractured reservoirs either double porosity or double permeability models are used. Both incorporate a matrix-fracture transfer term in the mass and energy balances. Due to the difficulty in modeling the physical processes taking place in the matrix-fracture transfer and the lack of experimental data, the matrix-fracture transfer term is not fully understood. This is especially true for nonisothermal processes.

Fine grid simulation results are used to design a 3-D laboratory matrix-fracture model to study the matrix-fracture transfer function for steam injection. A CT-Scanner will be used to measure the three-phase insitu saturations in the fractured model. The flow parameters were determined by using the results of several simulation runs. Among these are the steam injection rate, maximum expected pressure in the system and the number and the locations of the injection and production wells needed to clean and saturate the model for each run. Analytical heat transfer models were used to determine the heat losses from the model.

Fine grid simulations were used to investigate the sensitivities of the flow process to matrix-fracture properties such as capillary pressure and relative permeability. The simulations showed that matrix water-oil capillary pressure increased the oil recovery by increasing the water imbibition rate. On the other hand, fracture water-oil capillary pressure decreased the water imbibition rate and recovery. Matrix gas-oil capillary pressure had no effect on the oil recovery but fracture gas-oil capillary pressure had a positive effect on recovery by allowing flow of steam into the matrix thus increasing oil mobility. The effect of matrix relative permeability was found to be less important.

The experimental design was modified based on the numerical results. We give details of the experimental apparatus and show some results from preliminary experiments.
A Stream Tube Model for the PC
Authors: Dobitz U. K. , Prieditis John
Published: December 2007

CO2-Prophet, a water and gas flood prediction software product, has been developed by Texaco with support of the U.S. Department of Energy (DOE). This paper describes the model and presents case comparisons with physical models and commercial reservoir simulators.

CO2-Prophet has been shown to be a good tool for screening and reservoir management and is being released to the industry complete with a detailed user manual. Ease of use was emphasized in the development of the user interface. CO2-Prophet runs on PC compatible computers and following are some of its features:

A front end for easy reservoir parameter input. Several predefined patterns to simplify use. The ability to design patterns to fit most situations Fast computation. Multiple flood regimes so water, gas, and miscible floods can be modeled. Output in surface units and dimensionless formats. Output designed for importing into a spreadsheet

CO2-Prophet computes streamlines between injection and production wells to form stream tubes. It then makes flow computations along the stream tubes. The mixing parameter approach, proposed by Todd and Longstaffis used for simulation of the miscible process. CO2-Prophet uses the Dykstra-Parsons2 coefficient to distribute the initial injection into a maximum of ten layers, and then fractional flow calculations determine the flows and fluid saturations along the stream tubes. Program inputs are pattern description, relative permeability curves, initial saturations, injection rates, and reservoir-to-surface conversions. A new case can be set up and run in a few minutes making this program ideal for the screening of EOR projects and pattern comparisons.

The hardware requirements to run CO2-Prophet are an Intel® 386 based PC or better with at least 4 megabytes of RAM and 4 megabytes of disk space free. A math coprocessor is required for 386 or 486SX systems.
Project Design of a CO2 Miscible Flood in a Waterflooded Sandstone Reservoir
Authors: Davis D. W.
Published: December 2007

The Port Neches CO2 miscible flood project began CO2 injection in September, 1993 into a waterflooded sandstone reservoir along the Texas Gulf Coast. Sponsored by the U.S. Department of Energy (DOE) in their Class I Oil Program, this project will determine the recovery efficiency of CO2 flooding a sandstone reservoir which has been extensively waterflooded down to a residual oil saturation of 30%. The design of this project utilized the various tools available for predicting the recovery performance of such projects, with DOE's CO2 Predictive Model CO2PM1 and a compositional model being used. In addition a streamtube model2,3 has been developed to predict the recoveries associated with the waterflood and CO2 recovery processes. The validity of this streamtube model, the CO2PM program, and previous compositional reservoir simulation work, has been evaluated by the use of a compositional five-spot model where an equation-of-state for the current reservoir oil is incorporated. This work points out the streamtube model's ability as an effective screening device for CO2 flood prediction. Furthermore, the importance of properly characterizing the permeability within each layer of the reservoir is demonstrated by the improved recoveries seen in fining-upward sequence reservoirs.
Comparison of Actual Results of EOR Field Projects to Calculated Results of EOR Predictive Models
Authors: Pautz J. F. , Welch R. A. , Nautiyal C. M.
Published: December 2007

The 1984 National Petroleum Council (NPC) enhanced oil recovery (EOR) study used five computerized EOR process predictive models to estimate the potential for EOR. These models were reviewed by industry representatives and determined to be accurate when used with representative reservoir data. These models have continued to be a primary tool to assist the Department of Energy (DOE) and other agencies of the federal government to assess policy alternatives for tax reform, environmental regulations, petroleum research, and others areas. It is believed the estimates made by the models are representative for the United States petroleum resource although they may not be accurate for any one specific project or reservoir. Until recently, there has not been a data source that can statistically verify that belief.

The DOE encouraged EOR projects by starting the Tertiary Incentive Program (TIP) in 1978. Details of proposed projects were submitted, and the projects were certified as qualifying projects. Production and fluid injection data from those projects have been voluntarily submitted to the DOE since 1982. This program has produced historical data on more than 100 EOR projects with sufficient data for comparison with simulations using the predictive models. ՛

In this work, the predictive models were run using the average wellhead crude oil price for each year from 1980 to 1991 to estimate the potential production of the projects. The calculated production from the models was compared with the reported actual production until the project was terminated or no more production was reported. The results showed that steam production estimates were reasonable with a 50% confidence level for individual projects, whereas aggregate oil production for a group of projects compared more favorably. A rough estimate of the accuracy of the total aggregate oil production for a group of projects was ±20% at the 75% confidence level. Availability of data for other processes were insufficient for complete statistical analysis. Results for miscible gas projects showed that the carbon dioxide predictive model makes conservative estimates of tertiary oil production but optimistic predictions when the total oil target is considered. The surfactant option of the chemical flood model and the in-situ combustion model made reasonable oil production predictions. The polymer model made oil production estimates much higher than that reported for polymer augmented waterfloods.

The measured accuracy is for the combination of the models and the data. The results indicated that first upgrading the data and then the models would be desirable. Although this study indicates reasonable results for a group of reservoirs or projects, there was low confidence in predicted oil production for individual projects.
Master Plan To Increase Profitability of Heavy Crudes and Bitumen
Authors: McGee J. H. , Yibirin J. G. , Joubert Geovanny , Gallardo Bahilda
Published: December 2007

One of the largest accumulations of heavy oil and bitumen in the world are associated to Venezuelan reservoirs, where the Orinoco Belt alone has some 1.2 × 1012 Bis. of oil in place.

It is a well known fact that production of heavy oil and bitumen presents additional difficulties, as compared to more conventional hydrocarbons, in aspects such as: reservoir engineering, well completion and artificial lift, as well as surface facilities and associated procesess. These additional difficulties impact in high investments and production cost, which together with low market price result in marginal profitability.

In orden to improve these margins of profitability, a master plan was designed and implemented which consist in analyzing each aspect, considering new technology or new applications of existing technology that could make these hydrocarbons more competitive. Care was taken in that these technologies could interact with each other.

The following discussion is organized with projects with final evaluation first, on going projects next and future projects last. Also, where possible a sequence from reservoir aspects, to well completion and surface facilities is followed.
A Review of IOR/EOR Opportunities for the Brent Field: Depressurisation, the Way Forward
Authors: Braithwaite C. I. M.
Published: December 2007

Under the current waterflood development, it has been predicted that gas production from the Brent Field will fall off plateau in 1998 and, at field abandonment approximately 55% of the 6.9 Tscf GIIP and 54% of the 3600 MMstb STOMP would be recovered.

A review of EOR/IOR techniques was carried out at an early stage to define which of the various processes might be applicable in the Brent Field and would warrant further evaluation. The scouting study considered microbial, thermal, chemical, gravity drainage and miscible processes as well as reservoir depressurisation.

Of all the possibilities, surfactant flooding, immiscible (or near miscible) gas Injection and depressurisation were found to be technically viable. However, based on an estimate of the costs involved it was established that only reservoir depressurisation was economically attractive under the current and projected oil price trend.

With its high solution gas-oll-ratio (ranging from 1500 to 3000 scf/stb), depressurisation of the field, ultimately to 1000 psi, would liberate a significant proportion of the remaining solution gas and raise recovery by 1.5 Tscf. It was also established that, by extending the field's life, oil and condensate recovery would be Increased by 30 MMstb compared to a continuation of the ongoing waterflood.

Before the project could be initiated uncertainties such as aquifer influx, reservoir souring, compaction, subsidence and sand production had to be assessed and contingency measures identified. In addition, the full range of engineering options for the four platforms had to be costed and evaluated. With a planned expenditure of £1.3 Billion, the Brent Field will be able to sustain oil and gas sales well into the next century.
Magic Wand?—Solving the Recovery Problem of a Damaged, Turbidite-Type Reservoir by Horizontal Sections Kicked Off From Existing Vertical Wells
Authors: Werovszky V. P. , Szabari János , Geiger János
Published: December 2007

The number of horizontal wells in the world is steadily increasing. It has often been said that horizontal drilling is mature but in the economically less developed countries this technology nowadays begins to spread. The first successful steps could result in fast growing of this activity especially for gaining additional short term reserves, that is increasing recovery from known fields in these countries and good possibilities at the same time to go into these markets for the drilling companies.

This paper will illustrate in which way the first steps were made in Hungary according to the results of a detailed study about the possibility of using horizontal drilling technology overall in the Hungarian oil and gas production fields.

After ranking and screening the reservoirs, a gas capped low permeability oil reservoir which probably suffered also formation damage during its exploitation was selected first because of its very favourable economic parameters used for comparision and its suitable reservoir conditions.
Polymer Solution Extension Viscosity Effects During Reservoir Flooding
Authors: Hester R. D. , Flesher L. M. , McCormick C. L.
Published: December 2007

Both shear and extensional viscosity properties of a polymer solution must be characterized as a function of macromolecular structure and solvent-polymer interactions if fluid mobility performance during reservoir flooding can be predicted. When the flow rate through a porous medium exceeds a critical value, polymer coils can elongate and produce additional resistance to flow. Extreme extensional flow conditions can increase the fluid's resistance by two or three orders of magnitude greater than that due only to the shear flow field.

The conditions needed to produce high extensional fluid resistance depend upon 1) polymer properties, 2) porous media geometry, 3) fluid flow rates and 4) solvent composition. For a fixed porous medium geometry and flow rate, resistance increases with increasing macromolecular contour length and hydrodynamic polymer coil size. In turn, contour length and coil size depend upon macromolecular structure. Thus macromolecular structure can be adjusted to alter fluid resistance to extensional flow fields.
A Partially Scaled Physical Model of Cyclic Steam Stimulation for Recovery of Oil and Bitumen
Authors: Frauenfeld T. W. J. , Kimber K. D. , Sawatzky Ron , Ridley R. K. , Purewal Gurdeep , Drake Ken
Published: December 2007

Cyclic steam stimulation is the most widely used thermal recovery process for Alberta heavy oils and bitumen. This is a complex process where bitumen production is a result of the interaction of several mechanisms. Such a process may be studied by numerical models and by physical models. Physical models of a petroleum recovery process are a useful adjunct to numerical models. Physical models may be used to validate numerical simulations, and may also be used to study process for which the mathematical formulations are not well defined. A partially scaled physical model was used in this study, in order to evaluate available numerical simulators and to study mechanisms involved in the process.

In order to design and construct a partially scaled physical model of a cyclic steam stimulation, the important mechanisms must first be defined. The approach used was to run partially scaled lab models of the process, each of which scaled different mechanisms, and compare the model results with those of the prototype. This study compared 2 models, one built using the criteria developed by Pujol and Boberg, the other built using criteria developed by Kimber (Kimber #2). The former model scaled the relationship between pressure drive forces and gravity forces, while the latter scaled pressure drive forces and fluid expansion. The experimental results were compared to numerical simulations of both models and of a field scale prototype reservoir.

The experimental and numerical results indicated that gravity, the presence of non-condensable gasses and capillary forces were significant forces influencing oil production in the lab models. Capillary forces were less significant in the field scale simulations. The Pujol and Boberg model produced a better representation of cyclic steam stimulation than did the Kimber #2 model. Fracture dynamics and related effects were not represented. This type of a model is applicable to heavy oil reservoirs where there is sufficient initial fluid mobility to establish injectivity without fracturing.
Equations for Transient Gas Solubility Rates Improve Calculation of Volumetric and Work Efficiencies for Sucker Rod Pumps
Authors: Tebourski Hatem , Doty D. R. , Schmidt Zelimir
Published: December 2007

A correlation for transient gas solubility under pumping conditions has been developed which improves the prediction of volumetric and work efficiencies for sucker rod pumps with gas interference. Due to the reciprocating action of the rod pump, natural gas is forced into solution during the downstroke and out of solution during the upstroke. Throughout the pump cycle, the gas phase never reaches an equilibrium with the liquid phase. This paper presents experimental results quantifying the rate of natural gas solubility into and out of the oil phase under turbulent conditions. A new equation for two-phase volumetric efficiency in sucker rod pumps has been derived using transient gas solubility, gas compressibility, and gas-liquid gravitational separation. In addition, the work efficiency of the pump has also been analyzed using the transient gas solubility equations.
Use of Domain Decomposition for Simultaneous Simulation of Reservoir and Surface Facilities
Authors: Schiozer D. J. , Aziz Khalid
Published: December 2007

The main purpose of this paper is to describe the advantages of using domain decomposition when surface facilities are coupled to reservoirs in simulators. Full-held reservoir models that can handle both reservoirs and surface facilities are needed for accurate performance predictions and optimization. Use of conventional techniques for such models can be very CPU time intensive. For this reason, full-field models are either rarely used or they are simplified by handling surface facilities explicitly. Domain decomposition is useful either as an acceleration techniques to reduce computer time in implicit methods or, in conjunction with the use of different local timesteps in each domain, to improve accuracy of explicit methods. An example is presented showing a comparison of accuracy and CPU time for explicit and implicit methods, with and without domain decomposition. Small subdomains around wells are used to model the interface between reservoir and production facilities, and the rest of the reservoir is simulated with conventional techniques. This approach improves performance of full-field models. The prediction of reservoir performance accurately and efficiently can be accomplished by full-field models that use the domain decomposition technique presented in this paper. A fast full-field reservoir model is an important tool for the simultaneous optimization of the entire production system. The techniques presented here provide an efficient way to handle the coupling of reservoirs with surface facilities.
Prevention of Bit Balling by Electro-Osmosis
Authors: Cooper G. A. , Roy Sanjit
Published: December 2007

Work reported previously has shown that the application of a negative potential to a single point indenter or to a micro roller cone bit reduces the tendency of clays or shales to stick to the indenter or the bit, and thus reduces the tendency of a bit to "ball-up' while drilling. The effect is caused by electro-osmosis, the process by which, in the presence of an electric field, water migrates through the clay towards the cathode, and is liberated as a thin film at the metal-clay interface. This water film prevents adhesion of the clay to the metal of the cathode, and thereby reduces bit balling and increases ROP.

In this paper, we report results of further tests, using both roller cone and PDC drag bits in sizes up to four inches in diameter, drilling in both Pierre and Wellington shales. Making the bit the cathode again reduces the tendency of bit balling, and the rate of penetration is increased, in some cases by 100%. The greatest advantage is obtained at the highest rates of penetration. The power requirements to produce satisfactory results are modest, of the order of 10 Watts at 10 Volts for a four inch PDC bit.

This technique provides a novel method of preventing balling without the use of toxic chemicals, and should be of significant practical importance when applied to the field.
Waterflood/EOR Infill Drilling in Drill Site 9, Flow Station 2 of Prudhoe Bay
Authors: Kwan G. W. , Addie D. L. , Redman S. R.
Published: December 2007

This paper presents an inter-company, multi-disciplinary team effort to evaluate the infill drilling potential in Drill Site 9, Flow Station Two of Prudhoe Bay. The primary focus is on the construction of a 3D, four-component, Todd & Longstaff model for benefit analyses. A four-well drilling program was implemented in January 1993, based on results from stochastic modeling. The benefit estimates were reconciled and reality-checked with surveillance and production data.

Work conducted by Geology, Operations, Drilling, Materials, and Facilities Engineering staff among different companies in the Unit team are also summarized to provide a complete picture of this development drilling planning exercise. Special emphasis is placed upon the effectiveness of multi-disciplinary team work in minimizing costs and managing uncertainties, and the overall efficiency in meeting project deadlines.

In a water-alternating-gas miscible flood, the net recovery of an infill sidewell is estimated to be about 12% of its through-wellbore recovery, dependent on the reservoir description, time at which the sidewell is drilled, flood rate, individual well economic limits and project abandonment timing.

The methodology presented may be applicable in other waterflood/EOR areas of Prudhoe Bay for constructing a screening tool for evaluation of infill drilling opportunities. As long as the simulation results are reality-checked with offset well production, geological and surveillance data, drilling risk can then be significantly minimized with good contingency planning.
Cost-Effective Monitoring of Injected Steam Migration Using Surface Deformation Analysis
Authors: Bruno M. S. , Bilak R. A.
Published: December 2007

Steam injection produces subsurface volume expansion due to increasing temperature and pressure within the injection interval. These subsurface deformations induce measurable surface displacements, including vertical and horizontal movements and tilt. Measurements and analysis of induced surface displacements often provide a cost effective method to monitor the extent and orientation of injected fluid migration patterns over large areas and to monitor subsurface zones of recompaction that may contribute to increased oil production during cyclic steam operations. This paper describes field measurement and numerical analysis techniques used to monitor steam injection processes and describes two case studies demonstrating the practical application of this technology.
Study of a Mature Fireflood: MOCO-T
Authors: Northrop P. S. , Wilson J. L. , Soustek P. G.
Published: December 2007

This paper presents the results of a comprehensive study of Mobil's MOCO-T air combustion project in Kern County, CA. Since initial air injection in January 1960, over 63 BCF of air have been injected, representing over 30 times the estimated pore volume of the burned regions at 500 psig. Cumulative oil production to date is approximately 16.5 MMBO. Recent increases in project maintenance costs, excessive waste gas production and treatment expense, as well as new regulatory limitations on hydrocarbon emissions prompted a review of the technical and economic viability of the project.

The study centered around the estimation of current incremental oil due to air injection, which was derived using several analytical and empirical methods. The relative contributions of other potential recovery mechanisms were estimated analytically. The sum of these predicted contributions matched the cumulative production quite well. In addition to estimating volume of oil produced by combustion, theoretical burn volumes were calculated and mapped for each of six reservoir subzones. These maps were confirmed using well log and field data.

Several economic scenarios, including status quo operation, project expansion, and suspension of air injection, were investigated. Where possible, actual operating cost and revenue data were used.
Coiled-Tubing Completion Procedure Reduces Cost and Time for Hydraulically Fractured Wells
Authors: Harms D. A.
Published: December 2007

A unique completion procedure has been developed to reduce the cost and time to hydraulically fracture wells. In the procedure, coiled tubing is used to replace conventional tubing in most of the operations. This procedure is made possible by a wellhead design that enhances safety and simplifies switching from one operation to the next.

Hydraulic fracturing costs comprise the majority of the total cost for new diatomite wells. Multiple stimulations can be completed in a single day by using coiled tubing to cleanout or place sand plugs which are used to isolate the perforated interval between hydraulic fracture stimulations. This allows significant savings to be realized by fully utilizing the service company's entire minimum daily charge. The coiled tubing also functions as a dead string during fracture stimulations which allows real time monitoring of downhole fracturing pressures.

The new wellhead incorporates two unique ideas: 1) a hammer union tree cap which replaces the conventional flanged tree cap. Integral to the tree cap is a blast joint that provides protection from sand erosion when using coiled tubing as the dead string. The wellhead design enables the tree cap (with attached blast joint) to be quickly and easily exchanged with a fullbore lubricator; 2) a full opening gate valve located between the casinghead and the fracture wellhead. The valve is a safety device that allows any part of the wellhead to be removed while ensuring a completely controlled condition.
Absolute Isolation System Facilitates Successful Post-Gravel-Pack Isolation: Case Histories
Authors: Ross C. M.
Published: December 2007

During the performance of gravel pack operations, fluid loss problems that can compromise the productivity of the well sometimes occur. These fluid losses are experienced during work string and production tubing trips that are made into the well, resulting in the well being left in a fluid-loss condition. When consideration is given to managing this condition during the design stage of the completion, however, the operator can employ a special tool system that has recently been enhanced to address these fluid loss problems.

By using a washpipe attached below the gravel pack service tool and the specialized tool system, the formation interval can be isolated immediately after gravel packing (Figure 1). This system can also eliminate multiple work string trips, which saves job time and further reduces chances for fluid loss.

Two tools that provide a positive mechanical latching of an isolation washpipe assembly and a mechanical release to expand a travel joint for circulating-type gravel-pack operations are now available. The positively-locked absolute isolation system, which has been in use for two years, was developed from a shear-pinned version of the releasable washpipe system.

This paper will describe the tool system and how it can be used in combination with various completion design options to facilitate control of fluid loss and help solve other operational problems that occur during gravel packing. Other new enhancements to gravel pack technology, such as a large bore system for 5-/2-inch [13.97 cm] casing, will also be discussed.
Evaluation of the Pseudosteady-State Method for Composite Systems in Various Flow Geometries
Authors: Issaka M. B. , Ambastha A. K.
Published: December 2007

The pseudosteady state method, as applied to radial composite systems, has been used to estimate swept region volumes for thermal recovery projects with a good degree of success. However, the increasing scope and complexity of thermal recovery projects, as well as, the general heterogeneity of petroleum reservoirs, have necessitated the consideration of different flow geometries other than radial. Using analytical solutions, this study seeks to evaluate the applicability of the pseudosteady state method to composite systems in radial, linear, elliptical and spherical flow geometries.

To compare the solutions for the different flow geometries, the dimensionless pressure and time values have been normalized to account for the different definitions for dimensionless variables in each system. Results of the study indicate that, for the same mobility and storativity contrasts between the inner and outer regions, the dimensionless pressure derivatives for the four flow geometries can be collapsed into one curve during the period when the various systems approximate pseudosteady state flow. This observation confirms the pseudosteady state method as being independent of the regularly-shaped swept region shape.

Results also show that the pseudosteady state flow period begins at the same time for all four flow geometries. However, the time to the end of pseudosteady state varies. The linear flow geometry shows the longest pseudosteady state flow period, while the spherical flow geometry shows the shortest. The radial and elliptical flow geometries show the same duration of pseudosteady state flow.

The conditions under which a pseudosteady state flow period of a reasonable duration will occur for each of the four flow geometries are presented. Times for the start and end of the pseudosteady state flow period for each flow geometry, as functions of mobility and storativity contrasts, are also discussed. This study will help to identify the conditions under which the pseudosteady state method can be used to estimate the swept volume for thermal recovery projects under various reservoir situations.
Depth of Investigation for Elliptical Flow Problems and Its Applications to Hydraulically Fractured Wells
Authors: Liao Yizhu , Lee W. J.
Published: December 2007

This paper presents a method to determine "depth of investigation" for elliptical flow in homogeneous and composite reservoirs. Flow toward a well with a hydraulic fracture is an example. Formulas for determining depth of investigation for elliptical flow problems presented in this paper are not reported in the literature. The familiar radius of investigation for radial flow and depth of investigation for linear flow are two limiting forms of our depth of investigation for general elliptical flow. This paper also takes a hydraulic fracture as an example case and presents a few applications of our depth of investigation for elliptical flow problems.
Analysis of Infill Drilling in Kansas Hugoton
Authors: Ryan T. C. , Oberst R. J. , Hansen C. D.
Published: December 2007

The Hugoton Field in southwestern Kansas, western Oklahoma and northwestern Texas is the largest gas field in North America. Gas production is from the shallow (2,100+ feet to 2,900+ feet) heterogeneous, multi-layered Chase gas reservoir. This paper analyzes performance of wells in the Kansas Hugoton field. It compares volumetric and performance data from original and more recent infill wells within this field. These comparisons are shown by field, operator grouping, and infilled unit grouping using official deliverability tests and production history. The results are compared against geologic distributions, by producing layer, across the field. A cumulative comparison of the original versus infill well shut-in pressure difference is shown for the first 318 units infilled since infill drilling began in 1987. Some specific case studies are shown comparing monthly and daily well performance surveillance data. This analysis shows: (1) Some of the pitfalls of estimating initial gas-in-place (IGIP) and recoverable reserves, (2) The need to look at more than one type of analysis in reaching conclusions, and (3) Reasons why infill wells have not developed significant fieldwide incremental reserves.
Computerized Drilling Reports Strengthen Management's Decision Process
Authors: Wustermark R. V. , Hoff K. J. , Boyer C. M.
Published: December 2007

This paper discusses the benefits and difficulties with the implementation of a daily drilling report system using personal computers (PC's) at rig site throughout the Panhandle Region. The system's purpose being to capture and send data daily to the Borger, Texas office.

In 1991, laptop PC's were introduced to rig site operations. Training of field and office personal was essential, but proved to be less demanding than originally anticipated.

Benefits of the new system: A much higher accuracy (92%) of critical data compared to 62% of the old main frame system.Detailed daily costs are captured and are checked against the AFE cost estimate for discrepancies.Management is using the daily cost information for timely budget decisions rather than waiting for invoice payment system to provide cost information.

The main problems experienced are with the modems and cellular telephones. When operations are in fringe areas of coverage, equal distance between towers, or bad weather is moving through, loss of clear signals affects communication.

Overall the improved quality and quantity of data has more users asking for and receiving, in a convient, timely manner, the needed information to a number of myriad decisions and reports necessary to support an active drilling and completion program. PC's have been accepted by both office and field supervisors as an efficient way of doing today's business.
Case Study: Isolation and Restimulation of Granite Wash Zone in Mendota, NW Field Using Inflatable Packer Frac Liners
Authors: Hailey R. G. , McKaughan C. A.
Published: December 2007

The Mendota, NW (Granite Wash, SW) field in east central Roberts, County, Texas produces gas and gas condensate from the Cherokee Granite Wash section. Due to multiple producing intervals spread over a long vertical section, many of the wells in this field were fracture stimulated using the "limited entry" diversion technique1. Later comparison of actual gas recovery versus volumetrically calculated gas-in-place indicated very low gas recovery for wells originally stimulated by limited entry. It was concluded that some of the zones in these wells did not receive adequate treatment and would benefit from restimulation.

In order to fracture stimulate individual zones in wells with multiple open producing intervals, it is necessary to isolate the individual zone to be treated from the other open intervals. For the first well in the study area to be restimulated, a frac liner was configured utilizing two inflatable packers straddling a segment of tubing covering the upper producing intervals. This enabled fracture stimulation of the deepest zone with the treatment pumped down the casing and through the short liner interval, allowing an adequate injection rate with a reasonable injection pressure.
Research and Development Wells for Technology Transfer
Authors: Hansen J. T. , Perry K. F.
Published: December 2007

The Gas Research Institute (GRI) has developed a project that is aimed at accelerating the transfer of several hydraulic fracturing related technologies to the marketplace. The project, known as the "Research and Development (R&D) Wells for Technology Transfer", was initiated in the spring of 1992 and to date has been applied with nine producers on a total of 18 wells. The primary technology transfer vehicle used in the project is the cooperative research well, which is jointly sponsored by GRI and the participating producer, Emphasis is placed on heavy hands-on technology training and application by the producer, rather than on conventional GRI contractor involvement.

The new technologies that are being promoted in this project include: special core tests and analysis; formation stress testing; expanded logging programs; three-dimensional fracture modeling using FRACPRO; fracture diagnostics; fracture fluid quality control; and special well clean-up techniques.

Results from the project indicate that technology transfer using this technique can be effective under the right circumstances. The success is heavily dependent upon training, producer involvement, timing, and previous experience with hydraulic fracturing theory and technologies.
Proppant Effects on Fracturing Fluid Friction
Authors: Downie R. C. , Fagan R. E.
Published: December 2007

During a fracturing treatment, bottom hole fracturing pressure is used to evaluate the progress of the job. Direct measurement of bottom hole pressure is difficult. Surface treating pressure is commonly used to estimate bottom hole pressure, and must be corrected for fluid hydrostatics and friction losses in the tubing and perforations. This paper will illustrate the errors that can be made in fracturing treatment evaluation if proppant effects on fluid friction are not properly accounted for.