bluuebunny/crossref_metadata_2025 huggingface dataset:
Lithium Bromide Chiller Technology In Gas Processing
Authors: Huey Melton A. , Leppin Dennis
Published: December 2007

Melton A. Huey, P.E., and Dennis Leppin*

Lithium Bromide (LiBr) Absorption Chillers have been in use for more than half a century, mainly in the commercial air conditioning industry. The Gas Research Institute and EnMark Natural Gas Company cofounded a field test to determine the viability of this commercial air conditioning technology in the gas industry.

In 1991, a 10 MMCFD natural gas conditioning plant was constructed in Sherman, Texas. The plant was designed to use a standard, off-the-shelf chiller from Trane with a modified control scheme to maintain tight operating temperature parameters. The main objective was to obtain a 40 F dewpoint natural gas stream to meet pipeline sales specifications. Various testing performed over the past three years has proven that the chiller can be operated economically and on a continuous basis in an oilfield environment with minimal operation and maintenance costs.

P. 419
Computer Simulator of Coiled Tubing Wellbore Cleanouts In Deviated Wells Recommends Optimum Pump Rate and Fluid Viscosity
Authors: Walton I. C.
Published: December 2007

Key factors in the efficient removal of sand fill from deviated wells are the proper selection of a fluid and the pump rates. The operation should be designed to (1) reduce or eliminate the formation of beds of particles in the annulus between the casing and tubing, (2) maintain the particles in suspension and (3) transport the fill to the surface.

Currently, the only guidelines available for the preferred pump rate and fluid properties apply specifically to vertical wells. In essence, the recommendation is that the linear fluid velocity in the annulus should exceed twice the particle fall velocity. However, in a deviated well, the linear fluid velocity will not prevent the particles from falling to the lower side of the annulus and forming a bed. Unless the particles are perfectly supported by the fluid, formation of a bed can only be prevented by maintaining a sufficiently high level of turbulent activity.

A new design tool for coiled tubing (CT) cleanouts in deviated wells has been developed. Based on a mechanistic model of particle transport in deviated wells, it predicts the conditions under which a particle bed is formed, calculates the depth of the bed and determines whether the bed slides upward, remains stationary or slides back down the well. Moreover, it calculates the minimum pump rate required to achieve complete suspension of the fill for different fluid viscosities, sand pick-up rates and deviation angles, thereby allowing a simple assessment of the optimum design parameters.
Decision Tree for Selection of Artificial Lift Method
Authors: Heinze Lloyd R. , Winkler Herald W. , Lea James F.
Published: December 2007

Recent changes, upgrades and development in artificial lift equipment have expanded the considerations for selection of pumping method. This paper covers sucker rod pumping, continuous gas-lift, intermittent gas-lift, electric submersible pumping, hydraulic reciprocating pumping, hydraulic jet systems, plunger lift, progressing cavity pumping, and additional miscellaneous pumping methods. Changes in well conditions and equipment capabilities demand timely reviews of the original lift method decision to determine if it is still the best choice. Often the selection of the lift method is based on operating personnel / decision maker equipment familiarity. Included in the decision tree should be a long term economic analysis. This paper will consider how new advances in individual methods have changed their cost effectiveness and provided solutions to unique problems.

There is not a single lift system that is the most economic system for all wells. In order to access the practically and the economics of various methods of artificial lift, the first step is to generate an IPR (Inflow Performance Relationship) curve or a PI (Productivity Index). Then a profile of expected and desired production versus time should be determined. Figures 1 & 2.

With the above information, potential artificial lift methods can be introduced, including expected run lives and cost considerations for the most obvious methods. Detailed cost estimates of the well operating cost are then reported and compared to the numbers used in the economic evaluation of the field. The economics of low rate wells and high rate wells need to be adjusted to account for the economics of the project.

The economy of scale and simpler logistics of just using one lift system in most fields will probably not weigh up against the savings of using the most economic system on each well. Early in the life of the field the well may produce 100% oil with a moderate GOR. As the field declines and pressure maintenance begins GOR will increase and then rapidly decline while water production will increase. What range of BFPD is project, and what is the desired producing sand face pressure, Pwf.

Areas of evaluation of lift methods include (1) lifetime cost, (2) operating cost, (3) energy efficiency, (4) initial capital cost.
A Methodology to Optimize Fracturing Treatments in a Tight Gas Field of Northwest Louisiana
Authors: Kiburz D. E. , Sullivan S. C.
Published: December 2007

A systematic approach to optimize stimulation treatments on a field-wide basis has been developed for the Gray Sand reservoir, a member of the Smackover formation, in the Cotton Valley field of northwest Louisiana. Since the inception of the program, productivity increased 72%, costs reduced 14% and service quality significantly improved by

a team approach between operator and service company the application of technology to design and optimization tracking and evaluation of results.

This paper presents the results and advantages of using this three-step approach to optimize stimulation treatments in the Gray Sand reservoir. However, this methodology can be effectively applied to any field to optimize productivity and costs.
Depositional, Diagenetic, and Tectonic Controls on Frontier Formation Reservoir Characteristics: Moxa Arch, Southwestern Wyoming
Authors: Home John C. , Forster John R.
Published: December 2007

The Frontier Formation of the Moxa Arch in southwestern Wyoming provides an excellent example of the interplay among sedimentation, diagenesis, and tectonics on reservoir quality and performance. During the Cretaceous, thrust uplift and crustal loading occurred in the Sevier Orogenic Belt to the west of the foreland basin. The thrust sheets provided ample sediment to the Moxa Arch area during Frontier time. These sediments accumulated in wave-dominated deltaic, strandplain, coastalplain, and incised valley-fill depositional environments. The tectonic activity in the Sevier Orogenic Belt caused recurrent differential movement of orthogonally-shaped basement blocks along the Moxa Arch. These Movements created fractured lineaments at block boundaries. In addition, the recurrent movements of basement blocks influenced paleostructuring, diagenetic fluid migration paths, and sediment dispersal patterns of the Frontier.

The depositional facies of Frontier sediments control the primary porosity and permeability trends of Frontier reservoirs along the Moxa Arch. Post-depositional fractures caused by recurrent differential movements along zones of weakness at basement block boundaries secondarily enhance permeability and performance characteristics of Frontier reservoirs. Both the depositional facies and post-depositional fracturing of the Frontier influence the diagenetic trends affecting secondary porosity and permeability characteristics of Frontier reservoirs along the Moxa Arch. It is this complicated interplay of depositional, tectonic, and diagenetic influences that control the characteristics of Frontier reservoirs along the Moxa Arch.
Increasing Gas Reserves Through Technology in SW Wyoming
Authors: Duda John R.
Published: December 2007

Results from modeling the deployment of advanced E&P technologies indicate that natural gas "reserves" (possible, probable, and potential) in the over-pressured, tight portion of the Greater Green River Basin can be significantly increased. The reserve increases, attributable to advanced technologies, total about 20 Tcf for wellhead gas prices of $1.25/Mcf to $2.00/Mcf. A majority of these reserves are contained in the Almond and Lewis plays, at depths of 9,000 ft to 12,000 ft. In part, the reserve gains stem from economical exploitation of the gas resource at deeper depths.
The Effects Of Retrograde Liquid Condensation On Single Well Productivity Determined Via Direct (Compositional) Modelling Of A Hydraulic Fracture In A Low Permeability Reservoir
Authors: Carlson M. R. (Mike) , Myer J. W. G. (John)
Published: December 2007

Development of a retrograde condensate reservoir required accurate well productivity predictions for a capital commitment to gas processing facilities. Historically, Fussell identified that liquids condensing in the reservoir will result in a substantial productivity impairment. A single well model, which included a hydraulic fracture as part of the grid system, was developed to perform sensitivities for well test interpretation and to predict long term performance. Interesting results were obtained. The productivity of fractured wells was not impaired to the degree expected. Radial modelling confirmed the results obtained by Fussell. Current simulation technique allows for direct modelling of a hydraulic fracture instead of using an equivalent well bore radius. The distribution of pressure drawdown and condensate dropout around a hydraulic fracture results in limited productivity impairment. The methodology used and the results obtained are described.
Viscosity Behavior of Carbon Dioxide Treated Cut Bank Crude Oil
Authors: Cady G. V. , Mosawi Houssain
Published: December 2007

Carbon dioxide injection, either by huff and puff or displacement operations, results in a crude oil viscosity reduction at pressures below the miscibility conditions. Carbon dioxide miscibility occurs in reservoirs at miscible temperature and pressure, but these conditions are not possible in shallow reservoirs. Improved oil recovery in a shallow reservoir depends on the degree of viscosity reduction at the reservoir temperature and pressure. A recovery project's success depends on the interaction between the carbon dioxide and the reservoir system.

A research project carried out at Montana Tech to study the viscosity reduction and carbon dioxide solubility in Cut Bank crude oil at the reservoir's prevailing temperature and near fracture pressure shows a viscosity reduction ratio (crude-carbon dioxide mixture to original dead oil viscosity) of 0.22 at a pressure of 1000 psig and 90°F. An original mobility of 2 0 Md/cp improves to 91 Md/cp under a carbon dioxide recovery process at or near the reservoir's fracture pressure.

Based on our research, improved oil recovery operations in the Cut Bank Field, Montana, is viable when using a commercial on site carbon dioxide recovery or generating system to minimize the cost of CO2transportation. The major benefits ar oil viscosity reduction, mobility ratio improvement, gas drive, and crude oil swelling.
Quantitative Evaluation of Coal Seam Gas Content Estimate Accuracy
Authors: Mavor Matthew J. , Pratt Timothy J. , Nelson Charles R.
Published: December 2007

The proper measurement and analysis of gas desorption data from freshly cut coal samples is crucial to reliably predict the gas production performance and reserve potential of coal seam gas reservoirs. The technical literature offers may procedures for evaluating the total sorbed gas content of coal samples. This paper presents evaluations of the accuracy and comparability of gas content estimates for freshly cut San Juan Basin Fruitland Formation and Piceance Basin Cameo coal samples obtained using commonly practiced analysis procedures. Benchmark (or "ground truth") gas content values were assembled from pressure core and sorption isotherm data for comparison against gas content estimates obtained from conventional whole core, sidewall core, and drill cutting samples. Lost gas content estimate accuracy determined by the Direct (U.S. Bureau of Mines) Method,1,2,3,4 the Smith & Williams Method,5,6 and the Amoco Method7,8 was evaluated and compared. Assessments were also made of the sources and magnitudes of sampling and procedural method errors on the accuracy of the gas content estimates. The choices of sample type, gas desorption temperature conditions, and lost gas analysis method significantly affected the accuracy of the gas content values. The Direct Method analysis of conventional whole core, reservoir temperature gas desorption data provided the most accurate gas content values. Using ambient temperature gas desorption conditions rather than reservoir temperature conditions is the greatest source of error in gas content estimates.
Estimation of AOFP and Average Reservoir Pressure From Transient Flow-After-Flow Test Data: A Reservoir Management Practice
Authors: Kabir C. S. , King G. R.
Published: December 2007

A method for analyzing transient flow-after-flow (FAF) deliverability test data from both gas and oil wells is presented. The paper describes the derivation and application of this method to several field and synthetic cases. The method solves the transient absolute open flow potential (AOFP) and average reservoir pressure (p¯) by evaluating the parameters of the Forchheimer (a and b) and the empirical backpressure (C and n) equations together with p¯. Consequently, this new method allows one to describe the stabilized deliverability equation from transient test data, given reasonable estimates of the reservoir drainage area and shape. This approach is a significant improvement over currently available methods, which require an independent, a priori knowledge of p¯ for establishing a well's AOFP, along with the need to conduct a stabilized flow segment of the test.

All the resulting formulations are flexible enough to handle the pressure, pressure-squared, and pseudopressure approach for gas wells. This methodology is not restricted to gas wells as oil wells also lend themselves to the proposed analysis procedures. For oil wells, we used the pressure approach for single-phase flow and the pressure-squared approach for two-phase flow.

In the proposed technique, a well's orientation is unimportant. For example, a horizontal well's deliverability may also be characterized using the new method. In addition, layered reservoirs may be analyzed with the proposed technique. We also show that this method can be extended to injection wells.

Synthetic data were initially used to verify the method. Field data from several gas and oil wells, including a horizontal well and gas injector, were then used to demonstrate the method's application. In all cases, the new method shows good agreement with the results obtained from conventional methods, both in terms of AOFP and p¯.
Closure Stress Calculations in Anisotropic Formations
Authors: Iverson William P.*
Published: December 2007

The prediction of hydraulic fracture growth is controlled in part by the subsurface confining stress. Previous work has been based upon a simple relationship between vertical overburden stress and horizontal stress as a function of Poisson's ratio. Field measurements of closure stress have failed to consistently verify the relationship between vertical and horizontal stress, so that additional calibrations are required. Alternatively, consideration of an anisotropic Poisson's ratio results in a different relationship between vertical and horizontal stress. A portion of the observed difference between theoretical and calculated closure stresses is probably due to such an anisotropic effect. The azimuthal direction of induced hydraulic fracture growth is controlled by anisotropy in both tensile strength and Poisson's ratio. Field measurements of closure stress do not necessarily determine the minimum horizontal stress in anisotropic rocks. Geophysical measurements of anisotropy can greatly affect the engineering of hydraulic fracture treatments.
A Wellbore Model For Steam Injection Into Multiple Sands Through Limited-Entry Or Gravel-Pack Completions
Authors: Arthur J. E. , Hajdo L. E. , Ellison T. K. , Eggenschwiler M. E. , Chiou C. S.
Published: December 2007

Limited-entry perforations are used to meter steam injection into separate sand intervals within the same well. The steam flow rate into a perforation varies significantly with quality. In wells with gravel-pack completions, quality variations can also affect injection rates and heat distribution profiles. Tubing tail placement in either completion method may optimize performance.

A model was developed to investigate the effects of both limited-entry and gravel-pack completions, as well as the effects of tubing tail placement, on steam quality and heat injection distribution downhole. For mass and energy outflow calculations the reservoir is divided into different layers of unique properties. Steam rates entering each layer are dependent on wellbore and reservoir properties in that layer. Limited-entry perforations may be under critical or subcritical flow, depending on the properties in the wellbore and the reservoir. When the tubing tail is placed anywhere within the pay, steam will split at the tubing tail according to the wellbore and reservoir properties. The program can handle either a constant injection rate or a constant pressure at the well head.

The model has been successfully matched to bottomhole phase velocities and pressures obtained from field surveys. The program can be used to assist in completions designs, workovers, and in the interpretation of wellbore surveys.
OffsetSteam Injection Shut-In Guidelines During Drilling Operations: South Bel ridge Field Case Study
Authors: Bert D. R. , Chiou C. S.
Published: December 2007

Offset steam injection wells within a certain radius are typically shut in within a certain time period before drilling an in-field (increased density or replacement) well. The basis of this practice is that the reservoir pressure will eventually decrease to a minimum value, allowing drilling to proceed without problems. A study was undertaken to develop injection shut-in guidelines which consider specific reservoir conditions such as pressure, pattern size, and steamflood maturity.

This paper highlights the causes of steamflood well control problems and presents drilling practices which can reduce potential problems. A reservoir simulation was performed to predict the injector pressure falloff response in a South Belridge field steamflood. As a result of this study, over 80 in-field wells have been successfully drilled using a shorter shut-in time and radius. The major benefit is reduced injection well downtime and production loss associated with offset drilling operations.
Pulsed Neutron Spectroscopy Logs Add Value to Steam Flood Management Process by Monitoring Oil Saturation in Kern River Field, California
Authors: Zalan Thomas A. , Henshaw Paul C. , Abels Harold P. , Owens Brian K. , Guo Dunstan S. , Salaita George N. , Mikulich Weston
Published: December 2007

A PNS logging program was designed to evaluate the economic potential of vertical steam flood expansion and to identify bypassed oil, based on a comparison of oil saturations from a Pulsed Neutron Spectroscopy (PNS) log to conventional core in a Kern River field well. In the comparison, PNS log oil saturations agreed with those from conventional core within ±5.4 saturation units 68% of the time (log accuracy: 1 σ = 5.4). From multiple passes of the PNS log, it was found, for one effective pass at 60 feet/hour that the measurement repeats within ±5.7 saturation units 68% of the time (log precision: 1 σ = 5.7).

After the comparison of log to core, a multiwell logging program was designed to determine oil saturations for several reservoir zones above and below existing steam flood zones. The results were used to optimize patterns for future steam flooding. In addition, oil saturations were obtained for zones within the existing steam flood to determine the economic value and risk for producing bypassed oil.

For a proposed vertical expansion project, Expected Value Decision Analysis showed a benefit/cost ratio of 39/1 of running three PNS logs in the project area. The fraction of the total uncertainty associated with simulated production was reduced from 72% before to 39% after running the PNS logs. In addition, the PNS logs identified several million barrels oil in place that had not responded to conductive heating.
Determining Water Saturation in Diatomite Using Wireline Logs, Lost Hills Field, California
Authors: Bilodeau B. J.
Published: December 2007

There is a long-held paradigm in the California oil industry that wireline log evaluation does not "work" in Monterey Formation lithologies. This study demonstrates that it is possible to calculate accurate oil saturation from wireline log data in the diatomite reservoir at Lost Hills field, California. The ability to calculate simple but accurate oil saturation is important because it allows field management teams to map pay, plan development and waterflood programs, and make estimates of reserves more accurate than those based on core information alone.

Core data from eight wells were correlated with modem resistivity and porosity logs, incorporating more than 2000 ft of reservoir section. Porosity was determined from bulk density and water saturation was determined using the Archie equation. Crossplots of corrected core oil saturation versus Archie oil saturation (1 −Sw) confirm the accuracy of the algorithm. Improvements in the accuracy and precision of the calculated oil saturation will require more detailed reservoir characterization to take into account lithologic variation.
A Fast Track to Effective Waste Minimization: Government and Industry Working Together
Authors: Sims B. C. , Savage L. L.
Published: December 2007

The Railroad Commission of Texas (the Commission) has been involved in regulating the oil and gas industry, including preventing pollution of land and water, since 1919. The Commission recognizes the importance of its role with respect to waste minimization. Government can provide a good avenue for communication between members of all segments of the oil and gas industry. Also, it is in the government's interest for the oil and gas industry to be successful in its waste minimization efforts - successful waste minimization can increase industry ability to comply with regulations.

The Commission's Waste Minimization Program was formally launched in 1992. In May, 1993, the Commission prepared and distributed a survey to gather information on industry waste minimization practices and opinions regarding incentives and barriers. Survey participants and other interested persons attended a follow-up Pollution Prevention Workshop to express their ideas on how the Commission could effectively assist the industry in its waste minimization efforts. The Commission has incorporated many of these ideas in its Waste Minimization Program.

The Commission has since implemented several activities to promote oil and gas waste minimization. These include: 1) providing operators access to a technology transfer database that contains technical papers and articles addressing waste minimization in oil and gas operations; 2) publishing a waste minimization manual for distribution to oil and gas operators; 3) presenting a waste minimization workshop to operators and Commission staff at locations statewide; 4) publishing the "Waste Minimization Program Newsletter" to complement the other program activities; and 5) offering on-site visits to assist operators in assessing operations and developing waste minimization plans. Also, we are continuing to look for possible changes in existing rules and procedures to eliminate barriers to, and create positive incentives for, waste minimization efforts.

The oil and gas industry has responded enthusiastically to the Waste Minimization Program and provided numerous case studies of successful waste minimization efforts and other waste minimization information. This paper provides several examples of the case studies that have been provided by industry participants in the program.
Business Approach to Waste Management
Authors: Bradford R. A.
Published: December 2007

Today, resources of the oil and gas industry are pulled in many directions. It takes a major effort to manage the various priorities demanding attention. A company's effectiveness in balancing priorities determines whether it survives. An area increasing in its demand for resources is waste minimization. In order to minimize waste and reduce pollution possibilities, activities having the potential to cause environmental events must be managed in a conscientious, businesslike manner. The integration of environmental considerations into the business plan of the company or business unit will facilitate proper resource allocation to this area of the oil and gas business.

In this paper, policies, objectives and organization are reviewed as to how they are used to develop practical programs to allow field application of these business related factors. Monitoring, measurement and auditing are viewed as methods to sample the condition of the environmental elements. This condition "snap shot" provides a baseline for redirecting efforts to continuously improve the environmental management.
Gas Industry-Related Exploration and Production Waste "Demographics" Utilizing GIS
Authors: Daly Daniel J. , Stoa Rodney S. , Bassingthwaite Scott A. , Sorensen James A. , Charlton David S. , Mesing George , Evans James M.
Published: December 2007

Exploration and production (E&P) waste "demographics," i.e., an assessment of the occurrence and types of wastes, waste generation sites, management practices, and costs, has been completed for natural gas-related produced water and drilling wastes in the United States for the year 1990. Information acquired from purchased data sets, a review of the literature, and a telephone survey of over 300 regulatory and industry personnel was assessed at the geologic province, state, state/geologic province, and county level, with a focus on the onshore lower 48 United States.

For the lower 48 onshore states in 1990, results indicate that gas-related activities generated over 389 million barrels (MMbbl) of produced water and nearly 44 MMbbl of drilling waste. Together, these gas-related wastes represented less than 4% of the combined total of those waste types generated for both gas- and oil-related activities. Injection dominated disposal for produced water, but discharge was important in the Gulf Coast Basin and for select coal bed methane waters. Off-site management of liquids, mainly by injection, dominated for drilling wastes. However, nearly a third of the holes, which were drilled with air rotary systems, produced relatively small volumes of solids-dominated wastes, managed mainly on-site.
Delineation Of Biological Impact and Recovery of Selected Produced Water Discharges in Inshore Louisiana
Authors: Mulino Maureen M. , Rayle Michael F. , Francis John C. , Poirrier Michael A.
Published: December 2007

The benthos data presented are the results of sampling areas around the Delacroix Island Tank Battery #1 produced water discharge prior to and after termination. Data show recovery of the numbers of species and individuals at the discharge site six months after the termination of the discharge.
Discrimination of Ion Toxicity in Six Produced Waters Using the Freshwater Salinity Toxicity Relationships and TIE Procedures
Authors: Tietge J. E. , Hockett J. R. , Evans J. M.
Published: December 2007

Research to characterize the toxicity of common ions to freshwater organisms resulted in the development of predictive toxicity models (FW STR) for three freshwater species (Ceriodaphnia dubia, Pimephales promelas, and Daphnia magna). The FW STR models, derived from acute toxicity data, focused on the toxicity of seven common ions. These predictive models were used in conjuntion with Phase I TIE procedures to evaluate the contribution of common ion toxicity in six produced water samples ranging in total salinity from 1.7 to 58.1 g/L. Initial toxicities of all six samples were compared to the model predictions. Four produced water samples were found to have toxicity due to common ion concentrations only. Two samples were found to exhibit more toxicity than expected from ion concentrations alone. These samples were subjected to Phase I TIE procedures. Toxicities were reduced by specific Phase I TIE manipulations to those predicted by the FW STR models. Mock effluents were used to verify the results. The combination of the FW STR models with Phase I TIE procedures successfully quantified the toxicity due to common ions.
Shale Oil Survival in Underground Retorting By Combustion
Authors: Prasad R.K. , Thomas G.W.
Published: December 2007

A simplified mathematical model is developed to determine the amount of oil that survives passage to a hot fracture boundary in an underground retorting process in oil shale. Combustion at or near a fractured surface, heat conduction, oxygen diffusion, reaction of oil and oxygen, and perpendicular oil flow by diffusion and perpendicular oil flow by diffusion and convection toward the hot boundary are considered.

Appropriate assumptions are employed to arrive at upper bounds on the predicted recovery. Significant amounts of oil production are unlikely when the fracture temperature approaches 2000 degrees F. However, if the temperature is 1200 degrees F. or lower, the calculated upper bound is 64%. When more realistic assumptions are invoked, the computed results indicate no oil recovery.

The effects of oil migration velocity and the kinetic parameters were studied. Predicted recoveries were highly sensitive to the activation energy for temperatures below 2000 degrees F

We conclude that underground combustion in oil shale employing hydraulically or electrically created fractures apparently is not technically feasible unless appropriate means of reducing temperatures are employed. It appears that massive rock breakage is necessary to achieve substantial amounts of oil production.

Introduction

The possibility of underground retorting of oil shale appears attractive since mining, crushing, and spent shale disposal are not involved. However, it is necessary to induce a flow path in the rock since oil shale usually has no primary permeability and porosity (vugular porosity excluded). To porosity (vugular porosity excluded). To accomplish this, hydraulic fracturing, nuclear detonation, and electro-fracturing have been suggested. A number of thermal processes, such as hot fluid injection, forward combustion, reverse combustion, and conduction heating, can presumably be conducted within a single fracture presumably be conducted within a single fracture or system of fractures. Other methods have been proposed which combine two or more of these basic processes.

The success of any of the above processes will necessarily hinge on whether or not sufficient quantities of the liquid product can be recovered. In most cases, the system of fractures created in the shale must serve as the flow path for the produced as well as the injected fluids. Some or all of the produced fluids will frequently pass through high temperature zones to reach the fractures. To make intelligent performance predictions, it is important to know if the residence time and temperature levels will result in severe reduction in oil yield by destructive distillation and oil burning.
Pattern Of Chemical Changes In Fugitive Hydrocarbon Fuels In The Environment
Authors: Kaplan I.R. , Alimi M.H. , Galperin Y. , Lee L.P. , Lu S.T.
Published: December 2007

I.R. Kaplan, M.H. Alimi, Y. Galperin, L.P. Lee and S.T. Lu

This presentation describes a set of chemical tests which have been developed to characterize hydrocarbon fuels released into the environment. The methods examine various homologous series of hydrocarbons including straight chain (paraffins or n-alkanes), branched chain (isoparaffins or isoprenoids), cyclic (naphthenes or alkylated cyclohexanes), polycyclic (steranes and terpanes) and aromatic structures (BTEX, alkylated benzenes, PAH and alkylated PAH compounds and aromatic steranes). Each one of these groups of hydrocarbons has a different tolerance to alteration (evaporation, water washing and biodegradation). When used as an analytical system on environmental samples, the data obtained provide information on fuel type recognition patterns and on degradation levels of the various fuels.

Introduction

It has been well established. with a large literature citation extending back over forty years. that crude oil in the environment is altered by a series of processes leading to tar balls and asphaltenic residues.

These processes involve evaporation. water solution or water washing and biodegradation of various components. As a general rule, the low molecular weight hydrocarbons with the highest vapor pressure will escape from the crude oil rapidly. Next. in the presence of either standing water (ocean, lakes, rivers or aquifers) or rain, the soluble components begin to be removed. Benzene is the most soluble hydrocarbon (1750 ppm) followed by toluene (550 ppm) and other aromatic hydrocarbons. The light hydrocarbon gases such as methane and ethane are also among the most soluble hydrocarbons.

Following the selective removal of the most volatile and most soluble components of a crude oil, the residual components can remain in a sterile environment for an indeterminate period of time. Crude oil has been produced from early Paleozoic reservoirs. more than 500 million years old and Precambrian source rocks approaching one billion years in age. such as the Weiyuan in the Sichuan Basin in China and sediments in McArthur River Area. Northern Territory, Australia. The two controlling parameters that regulate the decomposition rate of the hydrocarbons in crude oil are (1) temperature and (2) the presence or absence of oxygen.

Although thermophilic bacteria that grow at temperatures between 90 - 100 C have been known for a long time, recent work by Stetter and his colleagues has shown that it is possible to grow bacteria at temperatures above 110 C at elevated pressures. Empirical observations, however. indicate that whereas in shallow crude oil reservoirs containing water. biodegradation of hydrocarbons occur, those more deeply buried with temperatures exceeding 82 C (the Pasteurization temperature) do not show evidence of significant biodegradation.

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Enhancing Area of Review Capabilities: Implementing a Variance Program
Authors: Leon Fernando De
Published: December 2007

The Railroad Commission of Texas (RRC) has regulated oil-field injection well operations since issuing its first injection permit in 1938. The Environmental Protection Agency (EPA) granted the RRC primary enforcement responsibility for the Class II Underground Injection Control (UIC) Program in April 1982. At that time, the added level of groundwater protection afforded by an Area of Review (AOR) on previously permitted Class II wells was not deemed necessary or cost effective.

A proposed EPA rule change will require AORs to be performed on all pre-primacy Class Π wells unless a variance can be justified. A variance methodology has been developed by researchers at the University of Missouri-Rolla in conjunction with the American Petroleum Institute (API). This paper will outline the RRC approach to implementing the AOR variance methodology.

The RRC's UIC program tracks 49,256 pre-primacy wells. Approximately 25,598 of these wells have active permits and will be subject to the proposed AOR requirements. The potential workload of performing AORs or granting variances for this many wells makes the development of a Geographic Information System (GIS) imperative. The RRC has recently completed a digitized map of the entire state and has spotted 890,000 of an estimated 1.2 million wells. Integrating this digital state map into a GIS will allow the RRC to tie its many data systems together.

Once in place, this integrated data system will be used to evaluate AOR variances for pre-primacy wells on a field-wide basis. It will also reduce the regulatory cost of permitting by allowing the RRC staff to perform AORs or grant variances for the approximately 3,000 new and amended permit applications requiring AORs each year.
Soil Remediation by Surface Heating and Vacuum Extraction
Authors: Stegemeier G. L. , Vinegar H. J.
Published: December 2007

A novel in-situ, thermal-vacuum method has been developed to remove contaminants from near-surface soils and pavements. Heat is supplied to the soil by downward conduction from a surface heater. Vaporized products are collected under an impermeable sheet into a vacuum system for further treatment or disposal.
Capillary Force Barriers in a Carbonate Reservoir Under Waterflooding
Authors: Namba T. , Hiraoka T.
Published: December 2007

This paper shows that the horizons with finite vertical permeability can act as barriers for the injected water and prevent water slumping due to the effect of capillary force in a carbonate reservoir. The proposed concept ‘capillary force barriers’ can explain the various monitoring results consistently including the data obtained from pulsed neutron logs and dynamic testing tools.
The Role of Technology and Decision Analysis in Reservoir Management
Authors: Thakur G. C.
Published: December 2007

The need to enhance recovery from the vast amount of remaining oil- and gas-in-place requires better reservoir management practices. Proper timing has a profound effect on the implementation of sound reservoir management technology on recovery efficiency. With this in mind, our goal should be to maximize volumetric sweep early in the project’s life. Trying to squeeze more oil from marginal projects will generally yield marginal to average results. The purpose of this paper is to identify the major attributes of a successful reservoir management organization and program and outline critical reservoir management issues and technical areas, and document benefits received from a team approach to reservoir management. In addition, the decision analysis technique is used to look at value creation as a result of reservoir management activities.

Any development of new reservoir management technology and its applications must be subjected to thorough economic screening so that use and support of such technology is justified based upon business needs.
A Rigorous Simulation Study of Water Coning and Edge Water Encroachment Using A Sector Model
Authors: Bu-Hulaigah E. H. , Rabbani G. , Lin C. , Al-Khowaiter A. O.
Published: December 2007

A simulation study was conducted in a shaly sandstone reservoir to study field observed coning behavior of a single well and recommend an optimum production rate for its sustained operation. The simulation model covers a 13 km by 5 km area to enable simultaneous simulation of individual well coning and regional edge water encroachment.

The effect of areal grid size on matching the observed coning behavior was investigated using Local Refined Grid(LRG). A 20-meter LRG model was chosen to perform various prediction cases to determine the optimum production rate for the coning well. The model was also used to investigate development options to accelerate the recovery of downdip oil, where a 50 feet shallower oil-water contact is observed.

This study shows the utility of sector models to study individual well coning behavior and optimize production rate restrictions due to coning, where the regional oil-water contact is dynamic. Conventional single well radial models are considered inappropriate in such cases.
Development of a Network and Gas Lift Allocation Model for Production Optimization in the Ras Budran Field
Authors: El-Massry Y. A. -W. , Price A. D.
Published: December 2007

The Ras Budran Field lies on the east side of the Gulf of Suez 5 KM offshore. The field commenced production in Jan 1983 and gas lift was implemented in 1985. The production system consists of 3 well-head platforms delivering production to a central process platform via 12" pipelines. The produced fluids are subjected to a firststage gas Ioil separation before being pumped onshore. All 15 wells are gas lifted with limited potential for natural flow. The high pressure gas lift supply is limited by compressor capacity and field production optimization is achieved by proper gas lift allocation between wells.

The paper describes the construction and use of a network and gas lift allocation model simulating the combined performance of the reservoir, production wells, flowlines and gas lift system. A network model analysis is performed by calculating the overall system pressure losses by iterating for pressures and flow rates at all production nodes having specified two points at the reservoir and separator. The integrated production network is treated as a single interactive model through the application of multiphase flow correlation(s) which best describe the performance of each component within the system in a step by step approach which is simple to follow and applicable to other fields. The constructed model predicts individual wells performance from the perforations to the firststage gas foil separation at the process platform, taking into account the interaction of the other wells in predicting pressure and flow rate responses. The gas lift allocation model has been used for routine production optimization and allocation of lift gas in a multi well networked model, as well as for prediction of future systern requirements and identification of debottle-necking opportunities.
Seismic Inversion for Reservoir Delineation and Description
Authors: Maver Kim Gunn , Rasmussen Klaus Bolding
Published: December 2007

Seismic inversion can be used to derive acoustic impedance information from seismic data. The seismic inversion methods globally optimised nonlinear seismic inversion and fully linear seismic inversion are introduced to describe a porous Zechstein carbonate interval in Denmark as a correlation exists between the acoustic impedance and porosity.

The globally optimised non-linear seismic inversion method enables a detailed delineation of a potentially porous carbonate interval due to interfaces that are derived as part of the inversion. The inversion is guided by the acoustic impedance log and uses a wavelet calculated at the well location. As the inversion does not use a prior model the result is not biased by the interpreter.

The fully linear seismic inversion method enables an evaluation of the possible variation in acoustic impedance that can be derived from the seismic data. The inversion method utilizes a prior model defined by extrapolating the low frequency trend from the acoustic impedance log along interpreted horizons. Based on this model the best fitting mean acoustic impedance section resolved in the seismic section is found. Additionally the upper and lower confidence limits of acoustic impedance, which can be derived from the seismic section, are defined.
Sequence Stratigraphy of the Hith / Upper Arab Formations Offshore Abu Dhabi, U.A.E.
Authors: Azer Samir R. , Peebles Ross G.
Published: December 2007

The Kimmeridgian Upper Arab zones A, B, and C, are prolific hydrocarbon bearing reservoirs in central and western Offshore Abu Dhabi, (OAD). They were deposited in an arid climate which dominated the Arabian peninsula during Late Jurassic times. The Berriasian to Tithonian Hith Formation which overlies the Arab reservoirs constitutes the cap rock, which just to the east of central OAD gradually pinches out and forms a N-S feather edge.

The Hith and Upper Arab zones A,B, and C form 450 to over 600 feet of massive to interbedded anhydrites with varying proportions of limestones and dolomites in central and western OAD. The Arab Formation in OAD is a major regressive unit which was deposited on a broad carbonate platform and prograded eastwards into an open marine shelf environment.

The Upper Arab zones A,B, and C consist of small scale shallowing upward cycles of varying thicknesses (6 to 30 feet) which typically consist of shoal grainstones (TST) passing upwards into thin bedded lagoonal burrowed mud/wacke-stones (MFS). These are overlain by coarse bioclastic grainstones capped by algal laminites and culminate into supratidal anhydrites, which pinchout eastwards. In the west, cycles are thicker and consist of intertidal pack/grainstones overlain by anhydrites. The parasequences or meter scale cycles have layercake stacking patterns arranged in transgressive, regressive episodes, and are driven by climatic, synde-positional tectonics and their associated low amplitude sea level fluctuations (eustacy).

Early evaporative and reflux dolomitization of peloidal and oolitic grainstones has greatly enhanced reservoir characteristics. Meteoric leaching associated with relative drops in sea level resulted in aragonite dissolution and reservoir enhancement Early marine cementation and late post-burial diagenesis such as anhydritisation resulted in reservoir deterioration.

The objectives of this paper are to develop a sequence stratigraphic framework, emphasizing cyclicity, fades architecture and diagenesis. Core and well log data geared with various inorganic geochemical analyses from four wells are used to constrain the current uncertainties in age dating and integrate the diagenetic signatures into the patterns of relative sea level change which considerably control the formation of those parasequences. This effort will help in better understanding and possible prediction of porosity in such prospective reservoirs.
Sequence Stratigraphy and Source Rock Potential of the Aptian (Bab Member) in East Onshore Abu Dhabi: A Model Approach to Oil Exploration
Authors: Azzam I. N. , Taher A. K.
Published: December 2007

A new geologic model of the Aptian Bab Member (Shuaiba Fm.) have been built, in East Onshore Abu Dhabi, using sequence stratigraphy and biostratigrapby. The model reveals that the Shuaiba is subdivided into two sequences (Upper and Lower). The first sequence is comprised of transgressive and highstand systems tract that can be distinguished in the Lower Shuaiba of Early Aptian age. The second sequence, the Upper Shuaiba, consists of deeper intrashelf basin sediments comprising a transgressive and highstand systems tract of Late Aptian age.

A practical modeling on the Shuaiba Fm. for identifying and calculating Total Organic Carbon (TOC) content and it’s thermal maturity have been adopted using well logs. The modeling indicated that the upper part of Lower Shuaiba (basinal facies) is a prolific, mature source rock especially in the northern part of the study area. Volumetric calculations for Shuaiba source rock indicated that most of the Upper Thamama oils have been generated and migrated from the mature Shuaiba source.
Monitoring of Two Gas Injection Pilots in an Offshore Abu Dhabi Field
Authors: Stofferis M. , Boibien C.
Published: December 2007

In one of the main producing reservoirs of an offshore Abu Dhabi field oil is produced by means of a strong bottom waterdrive. The reservoir is in its final stage of its primary development and gas injection is planned in the invaded part of the reservoir to boost total recovery.

Before embarking on a full field gas injection development, two pilot gas injectors were drilled in different parts of the reservoir and wet gas is injected below the miscibility pressure. According to a PVT-study, gas injection swells the oil by some 16% at the current reservoir pressure.

This paper summarises the various monitoring techniques, applied to these two pilots and discusses the further implications of some of the measurements. A split-up of the observed oil gains due to changes in oil mobility and flowing bottomhole pressure is also given.