bluuebunny/crossref_metadata_2025 huggingface dataset:
Laboratory Testing of Polymer Flood Candidates: San Francisco Field
Authors: Saavedra N. F. , Gaviria W. , Davitt J.
Published: December 2007

A technical feasibility study of a polymer-augmented waterflood process in San Francisco Field indicated that this enhanced oil recovery process might be commercially feasible. Since the feasibility study used hypothetical polymer properties, laboratory measurements of specific commercially available polymers were required. The experimental program was divided into three phases. A screening program to reduce the number of candidates. Basic fluid rheological data and quality were developed. For each polymer candidate, four polymer concentrations in three different salinity brines were prepared. Screen Factor tests, Filtration Ratio and viscosity measurements were obtained for each solution. The results were compared to select the best polymers for further testing.Core flooding experiments of the selected candidates. Parameters describing the rock polymer interactions (polymer adsorption and residual resistance factor) were developed. The polymer flow properties (viscosity versus shear rate) developed in the first phase were tuned to match the core flow experiments in a reservoir simulation model.A thermal aging study to verify that the selected polymer does not degrade significantly at reservoir temperature over time. This was a long-term test (six months duration).This paper describes the application of the procedures described in the American Petroleum institute publication RP63, dated June 1, 1990, "Recommended Practices for Evaluation of Polymers Used in Enhanced Oil Recovery Operations", and a case history of laboratory testing of polymer flood candidates.
An Overview of Streamline Tracer Modeling of Miscible/Immiscible WAG Injection IOR
Authors: Ruan F. , Carhart S. , Giordano R. M. , Grinestaff G. H. , Bratvedt F. , Olufsen R.
Published: December 2007

The streamline-based tracer model1 has been successfully deployed to history match and predict miscible and immiscible Water Alternating Gas (WAG) processes at the field scale. The tracer model is a simplified method for the three-phase WAG process, and is computed parallel to the traditional streamline waterflood model. This paper provides an overview to illustrate the relevant concepts and applications of the streamline-based tracer model. A Prudhoe Bay example of the vertical Miscible Injection Stimulation Technique (MIST) is presented to demonstrate and to verify the field use of the tracer model.
Modeling and Simulation of Non-Darcy Flow in Porous Media
Authors: Li Dacun , Engler Thomas W.
Published: December 2007

Consideration of non-Darcy flow effects is essential to adequately model high-velocity flow effects. The relationship between velocity and pressure loss relies on the Forchheimer equation, which includes an empirically derived non-Darcy flow coefficient. The key issue in analyzing the non-Darcy flow is to accurately determine the non-Darcy coefficient. In this work, a semi-theoretical equation is proposed to estimate the non-Darcy coefficient for heterogeneous, porous media. It was determined that two previous theoretical models, parallel-type and serial-type, are upper and lower bounds to the proposed general correlation. The proposed equation can be used to predict the non-Darcy coefficient in porous media where parallel-type and serial-type models are deficient due to heterogeneity and directional permeability.

The semi-theoretical equation was incorporated into a two-dimensional, single-phase gas flow simulator. This simulator was applied to a series of flow experiments where nitrogen was horizontally injected at various flow rates and in several directions into a 3-inch diameter by 3/8-inch thick heterogeneous core wafer. Results from the simulator successfully matched the experimental data, subsequently verifying the proposed correlation. In some directions, parallel-type or serial-type model was as good as the proposed correlation to be used to predict the non-Darcy coefficient; however, in one direction, the proposed correlation was better.

The general equation for the non-Darcy coefficient has been verified by comparing differential pressures from simulations and their counterparts from the wafer non-Darcy flow experiments. The equation will help investigators to reach a better estimation of the non-Darcy effect in porous media. Furthermore, the modeling of the non-Darcy flow developed in this paper can easily be incorporated into a reservoir simulator to account for non-Darcy effect at high velocities.
Microbial Enhanced Oil Recovery: Research Studies in the Arabic Area During the Last Ten Years
Authors: Sayyouh M. H.
Published: December 2007

More than ten strains of bacteria were isolated from Saudi and Egyptian crude oils and formation waters. Experimental investigation was carried out to identify the bacterial isolates, determine the compositions of the appropriate nutrients, conduct surface phenomena measurements. Based on the results obtained, it was found that presence of bacteria affected the solution phase volume, interfacial tension between oil and water, rock wettability, and relative permeability characteristics. These effects depend upon the bacterial type, nutrient type and concentration, salinity, temperature, composition of the crude oil.

A series of microbial displacement laboratory tests were carried out in homogeneous sandpacks and Berea sandstone cores using different types of bacterial solutions of glucose, sucrose and molasses based nutrients. The effects of nutrient type and its concentration, bacterial type, salinity, API, and permeability on oil recovery were investigated. Results show that the greatest oil recovery was obtained from activation of the indigenous bacteria by 1% molasses concentration. Some strains of bacteria were found to produce biogas, biosurfactant and biopolymers which increased oil recovery. The changes in sandpack permeability or API gravity have no effect on oil recovery.
Successful Acid Treatments in Horizontal Openholes Using Dynamic Diversion and Downhole Mixing—An In-Depth Postjob Evaluation
Authors: Surjaatmadja Jim B. , McDaniel B. W. , Cheng Alick , Rispler Keith , Rees Matthew J. , Khallad Abe
Published: December 2007

This paper discusses a relatively new acid-stimulation process that uses dynamic fluid energy to divert flow into a specific fracture point in the well, which can initiate and accurately place a fracture. The acid-stimulation process often uses two independent fluid streams: one in the pipe and one in the annulus. With this process, two different fluids can be mixed downhole with high energy to form a homogenous mixture.

Four such treatments in four openhole, horizontal wells were performed in one formation. The first well was acidfractured with coiled tubing to replace many small fractures along the open hole. The second well was acid-fractured with coiled tubing, but downhole mixing concepts were used to provide in-situ generation of CO2 foam. Fewer, yet larger, fractures were placed in this well. The third and fourth wells were treated with acid using rotating and nonrotating jetting tools while mixing the acid with CO2 downhole. Many small, near-wellbore fractures were expected in these wells.

Investigating the mechanism that may have contributed to these successes in the field is important. Laboratory tests were performed to analyze the jetting mechanism exposed to rock. The findings of these tests are reported in this paper.
Using Statistics to Evaluate a History Match
Authors: Uldrich David , Matar Saad , Miller Hugh
Published: December 2007

Three methods are proposed for quickly evaluating the history match of a numerical simulation to actual reservoir performance. All of the methods rely on computing a set of deviation values, each of which is defined to be a calculated simulator result minus the corresponding surveillance measurement value.

For any particular type of surveillance data, such as rates, watercuts, or gas-oil ratios, the deviation values can be grouped by well, by area, or combining all measurements in the database. The first two proposed methods rely on simple graphical presentations of each group of deviation values to show how well the simulation results match the surveillance data. Plotting together the results from more than one simulation run allows a quick comparison of the match for each run, which is useful during the history match process.

The third method converts each deviation value to a quantity called Match Factor, which is a relative measure of the confidence that the simulator actually reproduced the particular reservoir performance at the time the surveillance measurement was made. Weighted-average Match Factors can reveal the degree of match by well, by area, and by data type.

These techniques are especially valuable when matching reservoirs with a large volume of surveillance data. They can help focus the history matching process by identifying areas less well matched. They can identify when the history matching process is not significantly improving the match and can stop.
Evaluating Crude Oils by SARA Analysis
Authors: Fan Tianguang , Wang Jianxin , Buckley Jill S.
Published: December 2007

The effectiveness of some improved oil recovery schemes can depend on the composition of the target oil. Crude oils can be described compositionally by a number of methods. SARA analysis divides crude oil components according to their polarizability and polarity using a family of related analytical techniques. Problems arise because several of the analytical techniques in use do not produce identical results, although the users of the data rarely distinguish between them, assuming that SARA fraction values generated by any of the common techniques are essentially interchangeable. We examine this assumption for three SARA analysis methods: gravity-driven chromatographic separation, thin layer chromatography (TLC), and high pressure liquid chromatography (HPLC). Results for a suite of six crude oil samples show that a significant volume of volatile material that contains both saturates and aromatics is lost in the TLC analysis. Application of SARA fraction data to assessment of asphaltene stability is demonstrated.
Oil Deposits in Diatomites: A New Challenge for Subterranean Mechanics
Authors: Barenblatt G. I. , Patzek T. W. , Prostokishin V. M. , Silin D. B.
Published: December 2007

Because of their size and difficulties with oil recovery, the oil-bearing diatomite formations attract now special attention worldwide. For example, the giant diatomaceous oil fields in California, Lost Hills and Belridge, contain some 10 billion barrels of oil in place. Diatomaceous strata have peculiar geological structure: as a result of the cyclic deposition, the diatomite rocks are layered across width scales ranging from tens of meters to sub-millimeter. The diatomite rock is very fragile and its fracture toughness is low: the inter-layer boundaries are weakly connected and ready to part when the fluid pressure changes. When intact, the diatomite has porosity of 50-70% and is almost impermeable (0.1-1 md). Oil production from the diatomites was always difficult and started only 30 years ago after the introduction of hydrofracturing. The scanning electron microscopy images of the diatomite rock reveal a disordered microstructure with little grain interlocking and cementation. Therefore, fluid flow through the diatomite starts only after changes of the rock microstructure. The hydrofractures are not single vertical cracks, but are complex, multiply connected regions of damaged rock.

The current models of fluid-rock systems, e.g., Refs.,1,3,19 cannot capture the dramatic rearrangements of the diatomite microstructure caused by fluid withdrawal and injection, and have little predictive capability. In particular, these models cannot capture the intense rock damage during hydrofracturing, followed by the nonequilibrium countercurrent imbibition with the ensuing rock damage and hysteretic effects. To understand and predict reservoir behavior in the diatomite and limit well failures, a new micromechanical approach has been developed.
Simulating Fractured Reservoirs Using Adaptive Dual Continuum
Authors: Ganzer L. J.
Published: December 2007

This paper presents a new approach for the simulation of fractured or partially fractured reservoirs with a general-purpose reservoir simulator.

In many fractured reservoirs, fractures could be found in limited zones or "sweetspots". Hence, not all parts of the reservoir will typically require dual porosity or dual permeability treatment. The method presented in this paper allows creation of dual porosity or dual permeability cells wherever the attributes of the fracture geological model suggest to do so. The remaining - unfractured - part of the model can be treated like conventional single porosity areas. This approach will be called adaptive dual continuum. As a result, the generated simulation grid block models will resemble the real geological situation more closely than any other modeling approach. This will result in maximum reliability of the simulation model and allow better estimation of recovery for the various recovery processes modeled.

All fracture and matrix-fracture transfer properties are derived from the geological information and fracture intensity. The simulator - that applies an unstructured gridding method - will store them on a cell by cell basis. The paper will discuss the new workflow from generating the geological model by combining the strengths of continuous and discrete models, thereby achieving a high level of data integration until the consistent data export into the reservoir simulator.

The adaptive dual continuum approach was successfully implemented into a commercial reservoir simulator and several examples will prove the capability of this reservoir modeling approach for accurate and economic simulation of fractured or partially fractured reservoirs.
Near-Well Reservoir Monitoring Through Ensemble Kalman Filter
Authors: Geir Nævdal , Mannseth Trond , Vefring Erlend H.
Published: December 2007

In the management of reservoirs it is an important issue to utilize the available data in order to make accurate forecasts. In this paper a novel approach for frequent updating of the near-well reservoir model as new measurements becomes available is presented. The main focus of this approach is to have an updated model usable for forecasting. These forecasts should have initial values that are consistent with recent measurements.

The novel approach is based on utilizing a Kalman filter technique. The idea behind the Kalman filter is to incorporate the information from the measurements into the current estimate of the state of the model, taking into account the uncertainty that belongs both to the state of the model and the measurements. The uncertainty of the model is updated simultaneously with the model itself. A benefit of this approach compared to usual history matching is that the initial values for the forecasts will be in better agreement with the current measurements.

Originally, the Kalman filter had shortcomings for large, non-linear models. During the last decade, however, Kalman filter techniques has been further developed, and applied successfully for such models within oceanographic and hydrodynamic application. This work is based on use of the ensemble Kalman filter. The ensemble Kalman filter is easy to implement, and have some good properties for non-linear problems. Here, we demonstrate the use of this technique within near-well reservoir monitoring, focusing on its performance in forecasting the future production.
Microbiological Production of Surfactant from Agricultural Residuals for IOR Application
Authors: Bala Gregory A. , Bruhn Debby F. , Fox Sandra L. , Noah Karl S. , Thompson David N.
Published: December 2007

Utilization of surfactants for IOR is an accepted technique with high potential. However, technology application is frequently limited by cost. Biosurfactants (surface-active molecules produced by microorganisms) are commonly used in specialty markets such as food and textiles and have potential for IOR application. Currently, biosurfactants are not widely utilized in the petroleum industry due to high production costs associated with use of expensive substrates and inefficient product recovery methods. The economics of biosurfactant production could be significantly impacted through use of media optimization and application of inexpensive carbon substrates such as agricultural process residuals. Utilization of biosurfactants produced from agricultural residuals may 1) result in an economic advantage for surfactant production and technology application, and 2) convert a substantial agricultural waste stream to a value-added product for IOR. A biosurfactant with high potential for use is surfactin, a lipopeptide biosurfactant, produced by Bacillus subtilis. Reported here is the production and potential IOR utilization of surfactin produced by Bacillus subtilis (American Type Culture Collection (ATCC) 21332) from starch-based media. Production of surfactants from microbiological growth media based on simple sugars, chemically pure starch medium, simulated liquid and solid potato-process effluent media, a commercially prepared potato starch in mineral salts, and process effluent from a potato processor is discussed. Additionally, the effect of chemical and physical pretreatments on starchy feedstocks is discussed.

This paper presents an overview of previous work. This effort details the progress of research from initial observation of surfactin production from simple growth media through production of surfactin from process effluents from a local potato processor, and finally, potential reactor design for continuous operation.1,2,3,4
Geological Characterization of Naturally Fractured Reservoirs Using Multiple Point Geostatistics
Authors: Liu Xiaohuan , Srinivasan Sanjay , Wong Dale
Published: December 2007

The spatial distribution of fractures in a reservoir affects the displacement of fluids and the prediction of future performance. Realistic characterization of fractured reservoirs requires quantification and classification of fracture patterns on the basis of the underlying geological characteristics and developing reservoir modeling algorithms that can integrate connectivity based (multiple point) statistics related to fracture patterns. A methodology for summarizing the characteristics of fracture networks based on multiple point connectivity functions is presented. The paper also presents a stochastic simulation methodology for constraining the target reservoir model to the connectivity characteristics derived from analog models and to all other available reservoir specific data in the form of well information and seismic areal proportion maps.
Acidizing in Naturally Fractured Carbonate Reservoirs
Authors: Dong C. , Zhu D. , Hill A. D.
Published: December 2007

In this paper, we present a methodology for predicting the propagation of acid along natural fracture networks and the resulting etching of the fracture walls as well as the skin factor of an acidized naturally-fractured well. The natural fracture network is modeled as a system of intersecting fractures that form a main pathway for acid transport and dissolution. The tails of the intersected fractures increase the leakoff from the main pathway and are accounted for in the model. The fracture network acidizing model is supported by comparisons with laboratory experiments and smaller scale simulations that determined the nature of acid channeling at fracture intersections. Model results illustrate the effects of variations in fracture properties on acid propagation. Prats' model is used to calculate the skin factor of an acidized, naturally-fractured well. The model predicts deeper acid penetration (up to 5 meters) under matrix conditions than would be possible with only matrix flow. Acid-etched fractures of this length result in skin factors of -2 to -3, similar to that observed in many carbonate acidizing treatments.
Geological Sequestration of Carbon Dioxide in a Depleted Oil Reservoir
Authors: Krumhansl J. , Pawar R. , Grigg R. , Westrich H. , Warpinski N. , Zhang D. , Jove-Colon C. , Lichtner P. , Lorenz J. , Svec R. , Stubbs B. , Cooper S. , Bradley C. , Rutledge J. , Byrer C.
Published: December 2007

Sequestration of carbon dioxide (CO2) in depleted oil reservoir is a strategy currently being considered to reduce the amount of CO2 in the atmosphere. However, a better understanding and prediction of the geologic processes that control CO2 injection in porous geologic media is necessary before depleted oil fields can become a safe and economical sequestration option. This paper provides new experimental and modeling results from a Department of Energy's (DOE) National Energy Technology Laboratory (NETL) sponsored CO2 sequestration project investigating these issues. Geologic modeling and numerical flow simulations are used to study the feasibility of injection into porous media. Interactions between injected CO2, reservoir fluids and reservoir rock are taken into account, including CO2 dissolution in water and water reaction with reservoir rock. These results are helping to design geophysical monitoring studies to track the injected plume. Laboratory tests and reaction path simulations were also used to investigate the fate of injected CO2 with reservoir fluids and minerals during extended static tests with reservoir core and brines. Results may help identify long-term geochemical processes that will affect sequestration.
Monitoring WAG Pilot at VLE Field, Maracaibo Lake, by Perfluorocarbon and Fluorined Benzoic Acids Tracers
Authors: Hernandez C. , Alvarez C. , Saman A. , De Jongh A. , Audemard N.
Published: December 2007

It is widely accepted that comprehensive data acquisition programs are necessary for WAG management and pilot project interpretations. Common data acquisition methods used to monitore WAG processes are frequently analysis of separator testing, fluid composition, production/injection rates, pressures injection surveys, gas-oil ratios (GOR) and saturation logging. Chemical tracers have been used as a tool for monitoring water and gas injection, whereas for WAG process no experience in a field has been reported in Latinamerica. At the Lagocinco field, C2/VLE-305 reservoir (located in Maracaibo Lake basin) a WAG pilot project is currently being developed, using a chemical tracers program with Perfluorocarbon and fluorinated Benzoic acids. Five chemical tracers have been injected in both phases (water and gas) during WAG test as a surveillance tool for the process.

The aim to inject gas and water tracers was related to use breakthrough time and tracer production/injection history to get a better understanding of dynamic reservoir behavior and to support and upgrade the reservoir model.

This paper briefly describes the monitoring process achieved in Lagocinco pilot project, and some results of this monitoring in relation to the WAG process.

The result of the first water tracer test has indicated early breakthrough in four wells of the pilot project. One of the wells has increased oil production rate and three of them have maintained oil production rate and have decreased water cut and GOR as consequence of WAG process. The rest of the wells do not show a clear trend in tracer production, confirming heterogeneities in the pilot area. Zones not drained were identified and connection between the injector well and producer were characterized. The results of the first gas tracer have shown different distributions and velocities between gas and water. Finally, the second water tracer breakthrough was observed 3.3 months after its injection, just in one well, declaring that water distribution or path has changed as a consequence of WAG process.
Pressure Support Through Large Scale Gas Cap Water Injection At Prudhoe Bay
Authors: Jhaveri Bharat , Youngren Gary , Dozzo Joe , Schnell Lynn , Maguire Matt
Published: December 2007

The average reservoir pressure in the Prudhoe Bay field is declining at a rate of 25-35 psi/year. A large scale Gas Cap Water Injection (GCWI) project was recently sanctioned by the Prudhoe Bay Unit Owners to better maintain reservoir pressure and thus increase ultimate recovery. This paper presents key results from the reservoir analyses used in the design, evaluation and sanction of the project. Both mechanistic and full field compositional reservoir simulation studies were performed to develop a fundamental understanding of in situ recovery mechanisms and calculate project benefits. Reservoir uncertainty analyses included (1) assessment of early water breakthrough risks through reservoir description sensitivity studies, (2) evaluation of impacts on field gas and water injectivity and (3) quantifying impacts on gas recovery in the event of a major gas sales project. The paper also describes a field surveillance program that will be implemented to provide assurance that the project is performing as expected.
Next Generation Waterflood Surveillance: Behind Casing Resistivity Measurement Successfully Applied in the ‘A3-A6’ Waterflood at Elk Hills Field, Kern County, California
Authors: Starcher Mark , Mut Dave , Fontanarosa Mike , Davis Bob , Presmyk Chris
Published: December 2007

The project successfully used cased hole resistivity measurements to identify, isolate and access behind-flood-front oil in wells watered out as much as 10 years ago. The ‘A3-A6’ reservoir at Elk Hills has undergone peripheral waterflood for 20 years and has a Dykstra-Parsons permeability variation of ~ 0.7. Reserve development now targets bypassed oil.

In the past, determination of flood front position required open hole resistivity logs. Traditional cased-hole logs have been inconclusive as flood front monitoring tools. Only resistivity measurements provide the direct measurement to discern oil and water in this reservoir.

Watered out wells are mechanically prepped and then logged with a cased hole resistivity tool. Separation between the original and present resistivity curves indicates swept sands. When the open hole and cased hole resistivity curves overlay in sands, it gives a positive indication of unprocessed, bypassed oil reserves.

From this work, the ‘A3’ sand has been identified as unprocessed by the waterflood in several wells and processed in another well. Isolation and reperforation has resulted in commercial production in three wells to date. Behind casing resistivity measurement is the only logging method to successfully discern oil and water in the ‘A3-A6’ waterflood.

Every wet well is now reviewed as a candidate for this surveillance technology. Results demonstrate that behind-casing resistivity measurement is a next generation waterflood surveillance tool.
Quick Analysis of Steamflood, Bremer Fee, Midway Sunset Field, California, Using Production Enhancement Technologies (PET)
Authors: Heim Robin N. , Hampton Thomas J. , Laverty Bruce A.
Published: December 2007

This paper describes the application of a practical process to determine infill locations, reserves, and underperforming areas in cyclic and pattern areas in heavy oil fields.

Nuevo Energy Company had a need to quickly identify infill locations, reserves, and underperforming areas in Bremer Fee, Midway Sunset field, west of Bakersfield, California. The area used for the study consists of 393 wells over approximately 275 acres with just over 200 acres used in pattern and cyclic analysis. The challenge was to evaluate large data sets in a short time and a cost-effective manner.

The study incorporated techniques such as diagnostic plots, heterogeneity index, Voroni gridding, bubble maps, and pattern analysis from a well and reservir analysis software. The tools were used in a semi-automated process to quickly identify areas to improve steamflood performance by performing a geologic review, reserves analysis, production history review, cyclic well analysis, pattern analysis, and economic analysis.

From the study we determined oil-in-place and recovery, and looked at 393 wells in a low-cost, timely manner. We identified eight wells to be shut in, three wells to convert to injectors, several infill potential areas, and low-recovery areas. The infill areas independently validated Nuevo’s internal recommendations that had not been shown to Schlumberger staff performing the production enhancement technology (PET) analysis.
A Systematic Method to Estimate the Value of an Exploration Well
Authors: Dunn M. D. , Parnell L. A.
Published: December 2007

A systematic method designed to calculate the expected value of an exploration well is applied to an actual gas prospect in Cook Inlet, Alaska. This system of principles and procedures, herein referred to as the "Capen-Clapp" methodology, evaluates the significant factors that must be considered when a decision is made to drill an exploration well. These factors include geological risk, minimum economic reserve size, reserve size distribution, development costs, rate streams, commodity price, and discount rate.

The method is based on work published in Chapter 5 of The Business of Petroleum Exploration.1 The technique was developed over 20 years ago and has been used extensively for all types of exploration evaluations. Although this technique has been applied to hundreds of prospects, the application of this technique to an actual drill/no-drill decision has not been documented in the public domain due to the proprietary nature of most prospect evaluations. The source of the data is a published prospectus used to promote investment in the venture and therefore serves as a convenient case study to show how the technique is applied.

The discussion of the technique as applied in this case study shows that the Capen-Clapp methodology is thorough, easy to understand, and easy to apply to almost all types of exploration well evaluations. It accounts for all major factors that need to be considered when deciding whether to drill a prospect. It quantifies the risk in terms of one number, the expected value, which can then be used to rank the prospects of an exploration portfolio. This paper will benefit anyone faced with the challenging task of quantifying exploration risk and optimizing the value of exploration expenditures.
Petroleum Technology 2000
Authors: Birks J.
Published: December 2007

1979 Hydrocarbon Economics and Evaluation, Dallas, February 11–13, 1979

Introduction

During the past 10 years, and particularly since the OPEC price increase since 1973, more and more attention has been directed to the price increase since 1973, more and more attention has been directed to the decreasing availability of oil and gas supplies in the world's total energy picture. Reports from the 10th World Energy Conference in Istanbul and IEA picture. Reports from the 10th World Energy Conference in Istanbul and IEA studies, have a fairly wide range of estimates for the amount of conventional oil which remains in the earth's crust, and the amount of it which is likely to be recoverable allowing for improvements in technology and substantial price increases. The most widely accepted interpretation of these data has led to the conclusion that the physical limits to world oil production may lie in the region of 80 million bpd. I need hardly remind you that these physical limits may exceed the actual amounts which OPEC countries, or any others with potential for net oil exports, may actually choose to produce and export. Out of these technical and political considerations, there has grown a consensus of opinion that oil availability is likely to reach a maximum in the late 1980s, thereafter leveling and even decreasing before the end of the century. As a recent IEA report states:

" Developments in oil producing countries during recent months have demonstrated how difficult it is to predict accurately when such a situation might arise. They have, moreover, shown clearly how exposed the world's oil supply system is, even in the short term, to unanticipated supply disruptions.

Nobody known exactly how much oil remains to be found or how fast it can be found and produced. What is certain, however, is that the world is using oil at the rate of nearly 20 billion barrels every year, and increasing. To maintain the status quo, we therefore need to find at least the equivalent of two Prudhoe Bays every year.
Achievements Of Energy Policy Goals Of Mexico
Authors: Chavarria-Garcia Jesus
Published: December 2007

Introduction

MEXICO'S ENERGY POLICY IS STILL EVOLVING, BUT WE HAVE NOT HAD TO REVERSE OURSELVES ON ANY ELEMENT OF THE POLICY. WE ARE MOVING STEADILY TOWARD A COMPLETE AND SOPHISTICATED POLICY THAT ANTICIPATES MOST CHANGES AND INCORPORATES THE NECESSARY FLEXIBILITY TO ADJUST QUICKLY TO — WHATEVER CHANGES MIGHT BE NEEDED.

EACH COUNTRY'S ENERGY POLICY WILL NECESSARILY BE UNIQUE, SUBJECT TO — ITS OWN HISTORY, ITS ECONOMIC CHARACTERISTICS, ITS OWN TECHNOLOGICAL - SOPHISTICATION, AND KNOWN RESOURCE BASE FOR EACH FORM OF ENERGY. ALTHOUGH THE POLICY FOR EACH COUNTRY MIGHT BE UNIQUE, THERE ARE VARIOUS ELEMENTS OF POLICY THAT MAY CONTAIN ASPECTS COMMON TO SEVERAL COUNTRIES, AND SO PRECEDENT FROM OTHER COUNTRIES CAN BE USEFUL. THERE NOW EXISTS ABUNDANT PRECEDENT FROM OTHER COUNTRIES CAN BE USEFUL. THERE NOW EXISTS ABUNDANT EVIDENCE AS TO WHAT NOT TO DO.

WE WELCOME A SERIES OF TALKS WITH U.S. GOVERNMENT OFFICIALS THAT WILL COMMENCE SOON. WE WANT THESE TALKS TO BE SUCCESSFUL, AND ON OUR PART WE WILL TRY TO MAKE THEM SUCCESSFUL. WE VERY MUCH WANT TO SEE A STRONG AND ECONOMICALLY SUCCESSFUL UNITED STATES. IN FACT, WE ARE CERTAIN THAT A STRONG AND ECONOMICALLY SUCCESSFUL MEXICO WILL HELP THE UNITED STATES, NOT BE A DETRIMENT TO IT. THE POSSIBILITY OF MEXICAN NATURAL GAS EXPORTS WILL SURELY BE ON THE AGENDA OF THE MEETINGS; AND WE MAINTAIN AN OPEN MIND AND ARE WILLING TO LISTEN TO ALL REASONABLE PROPOSALS.
An Overview Of Project Financing For The Petroleum Industry (Domestic Cases)
Authors: Castle Grover R.
Published: December 2007

Introduction

There are four main types of Project Financings that are common in the Petroleum Industry and these are:Type I - The Oil and Gas Production LoanType II - The Carved Out Production Payment FinancingType III - Project Financings Backed By A Guaranty of Completion, andType IV - Project Financings Backed By A Continuing Undertaking Such As A Throughput Agreement.

In this paper, I shall describe each of these four Types and present a separate Case for each type in order to illustrate the concept involved. The Cases used in this paper shall be confined to domestic financings, but the concepts described could also be adopted to international financings as well.

TYPE I

The Oil and Gas Production Loan is a loan to an independent operator or another type of loan to a company or individual that is based solely on the collateral of reserves of oil or gas in the ground. In Table A, I have constructed a projection that could be applicable to properties owned by an independent operator and in the next section of this paper, I have constructed a hypothetical Financial paper, I have constructed a hypothetical Financial Plan covering a loan to that operator. Plan covering a loan to that operator.

FINANCIAL PLAN FOR CASE I

March 31, 1979

Financing For An Independent Operator (An Oil And Gas Production Loan)

Proposed 4 1/2 Year Oil And Gas Proposed 4 1/2 Year Oil And Gas Production Loan To Production Loan To INDEPENDENT OPERATING COMPANY

Amount: $16,000,000 (to be taken down on June 30, 1979)

Purpose: To refinance existing debts and for Purpose: To refinance existing debts and for acquisition of additional leases.

Amortization: Effective with runs as of July 1, 1979,30% of Gross Income from the Property(Property) evaluated by Independent Petroleum Engineering Consultants as of July 1, 1979 (Report) shall be applied on a monthly basis against the Loan through December 31, 1979 and thereafter 50% of Gross Income shall be applied against the Loan. All amounts applied against the Loan shall go first to interest and then to principal.

In the event that the outstanding balance on the Loan on the dates indicated below shall exceed the Maximum Balance (Maximum Balance), then the Independent Operating Company(operator) shall make an Additional Payment (Additional Payment) in an amount sufficient to reduce the outstanding balance below the Maximum Balance.

(000's Omitted) Maximum Dates Balance

December 31, 1979 $15,500 March 31, 1980 14,500 June 30, 1980 13,500 September 30, 1980 12,750 December 31, 1980 11,750
Wet Gas Metering: Trends in Applications and Technical Developments
Authors: Mehdizadeh Parviz , Marrelli Jack , Ting Ven C.
Published: December 2007

Wet gas metering covers a variety of measurements in production streams with high to very high gas volume fractions. There is a need for direct measurement of gas under these conditions in such applications as gas condensate and high GOR fields as well as many production operations where gas from separation systems may contain liquid. More gas will be produced in the future from remote and subsea fields where production, capital investment, and operating costs must be optimized. For example, real time measurement of gas and liquid flow rate are critical in a subsea production system which will improve well allocation, optimize reservoir production, and enhance flow assurance. A number of wet gas metering strategies and systems have been developed to address these needs.

This paper reviews the principle of operations of commercially available systems, and evaluates their strength and limitations in various applications. Available data from test loops, pilot and field installations are used to assess the performance and accuracy of these wet gas systems. The field installations are used to identify the types of applications as well as the application trends that have utilized these systems. The paper also assesses the potential benefits from the deployment of a wet gas metering system.

The technologies employed in the current systems impose performance and accuracy as well as operational limitations. These limitations are outlined and evaluated in terms of operator expectations and requirements. The analysis is used to outline a list of issues that an operator has to consider in selecting and justifying a system for wet gas measurements in an asset development.

New developments that are ongoing or must be undertaken to address the limitations of the current wet gas metering systems are also reviewed. The implications of these developments to extend the future applications of wet gas metering systems are discussed.
Cubic Equations of State Applied to HT/HP and Highly Aromatic Fluids
Authors: Pedersen K. S. , Milter J. , Sørensen H.
Published: December 2007

PVT data are presented for 38 reservoir fluids counting fluids dominated by paraffins, heavy aromatic fluids with a significant content of C81+ and high-temperature-high-pressure (HT/HP) reservoir fluids. By properly taking into account the compositional differences, these fluid types can all be represented using a classical cubic equation of state (SRK or PR) with volume correction. The plus fraction is split into carbon number fractions and EOS model parameters assigned to each fraction. To keep the number of components at a manageable level the carbon number fractions are lumped into pseudocomponents, each containing several carbon number fractions. Hydrocarbons as heavy as C200 are considered when splitting up the plus fraction. Neglecting the content of components heavier than C80 will give a false picture of the phase behavior of heavy aromatic fluids. Correlations are presented for Tc, Pc and ω as a function of molecular weight and density. Problems are experienced representing the thermal expansion of stable oils using cubic equations of state in the classical form. It is shown that this deficiency can be cured by introduction of a temperature dependent volume correction term.
An Evaluation of the Application of Low Field NMR in the Characterization of Carbonate Reservoirs
Authors: Mai An , Kantzas Apostolos
Published: December 2007

Conventional reservoir analysis has always been an extensive process. In order to properly characterize a reservoir, cores and/or logs have to be obtained. Both core and log analysis is expensive and time consuming. NMR is an attractive alternative to these tools due to the fact that in theory, only one measurement is required. However, the conventional methods of interpreting NMR data only seem to work for simple sandstones. A new method of interpreting NMR data is required for complex porous structure such as carbonates.

It was found that NMR can predict porosity that is similar to the values obtained by gas expansion. By using the NMR data at fully saturated and irreducible water saturation (Swi), a T2cutoff value was obtained for each sample that separates the bound and movable fluid signals. It was found that T2cutoff for carbonates is not 100 ms as is widely believed by many people who have analyze NMR in carbonates. A correlation for T2cutoff was found as a function of the size of the last peak and its geometric mean. A correlation was also found for Swi, which was a function of the size of the first and last peak.

The Free Fluid and the mean T2 permeability models were evaluated. It was seen that the predictions from these models were not adequate. Another permeability model was developed, which is expressed in terms of the size of the first and last peak of the NMR spectrum obtained from the fully saturated sample. It was found that the correlation did a better job of predicting the permeability values. The new model has its own limitations, a method is currently being investigated to overcome these limitations. Despite these limitations, however, the new NMR permeability model provides better estimates of carbonate permeability than any other established methods.
Reservoir Modeling Methods And Characterization Parameters For A Shoreface Reservoir: What Is Important For Fluid Flow Performance?
Authors: Jian F. X. , Larue D. K. , Castellini A. , Toldi J.
Published: December 2007

About fifty reservoir characterizations were built using seven different modeling methods, and by varying a combination of reservoir characterization parameters using Experimental Design. The methods include: 1) simple sequential gaussian simulation (SGS); 2) SGS with stratification; 3) SGS with reservoir quality map trend and no stratification; 4) SGS with reservoir quality map trend and stratification; 5) sequential screening simulation with 3D trend; 6) truncated gaussian simulation with trend and 7) general marked point process. These fifty models were all subjected to fluid flow simulation with an active aquifer and limited peripheral waterflooding.

The results show that oil recovery at 95% water cut ranges from 29% to 34% in these fifty models despite the large apparent visual differences between them. However, there are large differences, some greater than 200%, in water breakthrough time, water cut and cumulative water production. Based on fluid flow performance, these fifty models are classified into three groups. Group 1 includes models constructed using short variogram ranges in Methods 1 to 4, or medium variogram ranges without stratification in Methods 1 and 3. They behaved more homogeneously and produced flow characterized by later water breakthrough and lower watercut. Group 2 are those models constructed using long variogram ranges in Methods 1 to 4, or medium variogram range with stratification in Method 2 and 4. They behaved more heterogeneously and produced early water breakthrough and high overall watercuts. Even though the mean permeability was similar in the oil zone for the two groups of models, the effects of continuity imposed by the variogram and stratification controlled this disparate behavior. Models of Methods 5 to 7 comprise Group 3, which produced the earliest water breakthrough and the highest overall watercuts. We interpret the difference in water breakthrough time and watercut between Group 2 and 3 to be a result of the higher average permeability (by 100-200 mD) in the oil zone of Group 3 models.

Do more complex, geologically realistic models provide the best frameworks for predicting flow performance in sandy shoreface reservoirs with good well control? Some of the simplest models we constructed provided similar flow simulation results as the most complex and soft-data conditioned models. What we do observe, however, is that the more soft conditioning data used and the more complex geologic models tend to give a restricted range in full field flow performance.
Source Parameters of Hydraulic Fracture Induced Microseismicity
Authors: Urbancic T. I. , Maxwell S. C.
Published: December 2007

Microseismic results are presented for hydraulic fracture stimulations monitored in the Cotton Valley, East Texas. In particular, we examine whether additional information on the microseismic source such as the apparent stress release values can be used to effectively identify differences in the generation process of individual or clusters of microseismic events and the development of the overall hydraulic fracture in both space and time. Trends in apparent stress have been used to establish different modes of failure, with increased apparent stress values at the leading edge of the hydraulic fracture and lower apparent stress values behind the leading edge. We suggest that the failures are along a pre-existing network of fractures and include significant non-shear components of failure for events occurring behind the hydraulic fracture front. At the extremities of the hydraulic fracture as the stimulation proceeds we suggest that the redistribution of stresses as a result of the injection increase the average shear driving stress resulting in shear dominated failures. Overall, the hydraulic fracture can be characterized by regions of shear and nonshear type failures, further suggesting that the relative permeability of the fracture network can possibly be identified.
Integrating Pressure-Transient and Seismic Data to Determine the Characteristics of Single-And Double-Porosity Reservoirs
Authors: Cardona R. , Ozkan E. , Batzle M.
Published: December 2007

This paper presents an approach that integrates pressure transient and multi-component seismic data to determine the characteristics of single- and double-porosity reservoirs. It is shown that a functional dependence exists between the well-test-determined storage capacity ratio and the seismic estimate of the normal fracture compliance. This functional dependence provides a means to obtain an estimate of the normal fracture compliance from well-test data or an estimate of the storage capacity ratio from seismic data. Obtaining estimates of these parameters by independent means helps reduce the nonuniqueness problem encountered in the interpretation of well-test or seismic data by reducing the number of parameters to be determined. In addition, it is shown that assuming a fracture model, the fracture density may be predicted from the storage capacity ratio. The application of the approach developed in this work is demonstrated by the analysis of the pressure buildup data from the Weyburn Field.
Design of a Crude Oil Dehydration Unit
Authors: Noïk C. , Trapy J. , Mouret A. , Laborie G.
Published: December 2007

The purpose of the study is to develop a compact electrocoalescer. To improve oil/water separation, definition of optimized conditions for coalescence of water droplets under an electrical field in combination with optimal hydrodynamic performances was performed. Numerical simulations carried out with the CFD code fluent permit to design a new dehydrator integrating the three functions of electrocoalescence, centrifugation and phase separation.

A first part consists of two concentric cylindrical vessels used as electrodes with a tangential flow introduction. Then the speed of water droplets is accelerated in a second step by centrifugal effect. Finally, the water flow is separated from the oil phase in a third part. A laboratory prototype was built and tested in various conditions of flow rate and with different types of crude oil/water emulsions. Encouraging results led to define and patent a new concept of compact centrifugal electrocoalescer.