bluuebunny/crossref_metadata_2025 huggingface dataset:
Qualification of a Nonintrusive Multiphase Flow Meter in Viscous Flows
Authors: Atkinson D. I. , Bérard M. , Ségéral G.
Published: December 2007

New requirements have recently appeared for accurate and reliable flow rate measurements in various operational areas where viscous fluids are produced. Heavy oil as produced in Venezuela, Confederation of Independent States (CIS), Brazil, Angola and China and lighter oil emulsified with large water cuts (worldwide) present new challenges to multiphase metering.

The compact, cost-effective multiphase meter described in this paper is intended to replace large, costly test separators designed for heavy oils. The meter is non-intrusive and combines a classical venturi to measure total mass flow rate and a dual energy gamma-ray composition meter to measure oil, water and gas fractions. A benefit of this compact design is that the meter can be switched from one well to another and provide robust, consistent flow rate measurements without any flow recalibration.

According to published single-phase flow literature, liquid viscosity plays an important role in meter performance. Oil companies are becoming increasingly aware of these problems and want more evidence that a multiphase meter will perform regardless of fluid properties.

To qualify the multiphase meter in high-viscosity flows, we conducted comprehensive flow loop tests in Venezuela. The challenge was to gain a solid understanding of viscosity effects even in the presence of large amounts of gas, and for the entire operating envelope of the meter. These test results have been used to refine the meter interpretation model to maintain the metering accuracy in these conditions. The interpretation includes a mixture viscosity model based on the dead-oil viscosity; for permanent monitoring and periodic testing, the effluent viscosity variations are updated when pressure, temperature or water cut is changing.

To demonstrate that the specified measurement accuracy was achieved up to the highest viscosities tested (several thousand centipoise), the meter was field tested in comparison with a test separator. We present the results of 54 jobs.

Until recently, the only multiphase meters available to measure viscous oil flowing with gas were intrusive. Positive displacement meters, such as oval gears, twin helical screws or vane types, were used to measure the total gas-liquid volume flow rate. These meters are very sensitive to severe slugging in the upstream pipeline and prone to mechanical damage from produced solid particles.

The lightweight, small-footprint meter described here solves these problems. Consistent flow rate information can be obtained even when the meter is switched from well to well. Fluid property or flow regime changes do not affect the flow rate measurement.
Rate Effects on Centrifuge Drainage Relative Permeability
Authors: Skauge Arne , Poulsen Susanne
Published: December 2007

Estimation of oil drainage relative permeability can be made from centrifuge measurements either by single-step or mul-tistep experiments. This paper compares relative permeability calculated from the two centrifuge methods to data from long core gravity drainage gas injection.

Simulations of centrifuge single-step drainage experiments at varying rpm have been performed, with independent measured capillary pressure included. The relative permeability curves hereby estimated seem to be rpm (rotations per minute) dependent.

The paper gives recommendation for a minimum or critical Bond number for which capillary pressure can be ignored in drainage relative permeability calculations. Simulation of long core gas gravity drainage experiments supports the results of the single-step centrifuge drainage at low rotational speed.

The multi-step centrifuge experiments have the benefit of simultaneous calculation of both relative permeability and capillary pressure. However we find the multi-step technique to overestimate capillary pressure and underestimate oil relative permeability. These results come from comparing with direct capillary pressure measurements and relative permeability derived from long-core or single step centrifuge data corrected for capillary pressure.
A Hybrid Streamtube Simulator Using A Semianalytical Method
Authors: Baek Munseok , Hewett Thomas A.
Published: December 2007

A hybrid streamtube simulator is developed using a semianalytical method. This hybrid simulator applies to steady-state, incompressible, two-phase, field-scale problems, where the effects of gravity can be neglected. The underlying idea of the hybrid streamtube method is to decouple a large 3-D problem into multiple cross-sections along areal streamtube bundles. Using the calculations of cross-sections, the areal recovery is computed. This method is based on the assumption that the effects of a changing mobility field can be accounted for by using fixed streamtube geometries with updated flowrates. In each cross-section the semi-analytical method is applied, which uses the single-phase pressure distribution and the 1-D Buckley-Leverett solution along the streamtube. The distribution of pore volume along each streamtube is calculated by using the Time-Of-Flight method. This information and the pressure solution are used to calculate oil recovery by the semianalytical method. Unlike previous hybrid methods, the simulator developed uses a streamtube method in each cross-section. Due to the simple calculations and small arrays the method developed shows a very fast calculation speed compared to a conventional finite difference simulator (ECLIPSE), a streamline simulator (3DSL) and another streamtube simulator (STUB3D). The simulator developed shows good agreement with other methods for an end-point mobility ratio range from 1 to 50. The hybrid streamtube method (HST) was faster than the updated streamline method (3DSL) by factors of 1 to 3 orders of magnitude, and the conventional finite difference method (ECLIPSE) by factors of more than 3 orders of magnitude.
Crack Tip Plasticity: A Different Approach to Modelling Fracture Propagation in Soft Formations
Authors: Martin A. N.
Published: December 2007

Over the last 15 years or so, the numerical simulation of hydraulic fracturing has improved beyond recognition. Considerable time and effort has been spent on the production of these models and on their verification with field trials. In spite of their differences, these models still employ, to a lesser or greater extent, the same basic theory of fracture propagation - first put forward in the 1920’s and used in the original 2-D fracture models – known as Linear Elastic Fracture Mechanics, or LEFM. Although the various organisations producing fracture propagation models have extensively modified the original LEFM theory, mainly to allow for the effects of non-linearity at the crack tip, the original assumptions of LEFM still hold true. Failure is by brittle fracture, with no significant plastic deformation of the rock – even at the fracture tip. This assumption is probably valid for most of the formations fractured by the industry today. However, an increasingly important sector of the industry is now stimulating very soft, ductile formations, where the assumptions of linear strain and no significant plastic deformation are not reliable. Fortunately, LEFM is not the only way to model fracture propagation. The Crack Tip Plasticity (CTP) method assumes a fracture tip of finite radius, with a zone of plastically deformed material around it. This plastic zone acts to absorb extra energy from the fracturing fluid, making it harder to propagate fractures through formations with significant plastic deformation. This in turn means that, for a given ductile material, fractures will be smaller and less conductive than those predicted by LEFM. An understanding of CTP could help predict how much smaller the fracture really is, and could also help explain why LEFM-based fracture simulators cannot adequately model very soft formations.
A Model for Sand Screen Running on Marnock: A Horizontal, Near-HPHT Well Development
Authors: Swanson Bruce , Inglis Charles , Reed David
Published: December 2007

The Marnock field, situated in the Central North Sea, is the first development in the North Sea to combine the challenges of near HPHT conditions (9100 psi and 310 F) with a horizontal sand screen completion. Once completed, the wells have proved to be highly productive with production rates up to 120mmscf/day. However, well completion, and especially installation of sand screens, has proved problematic with two out of the four wells completed with screens off-bottom

This paper describes the development of an empirically based model compiled from information gained during the drilling of reservoir sections and screen running on four Marnock wells. The model represents the accumulated learning over the four well development and was developed to capture learning as well as provide a means of assessing the risk of well designs failing to get screens down during well planning. The basis of the model is an analysis of the 15 factors considered relevant to creating a wellbore in which screens will successfully be run to bottom - these included aspects such as hole tortuosity, hole length and maximum angle. This collected data set is then used within a set of rules based on the well construction team’s experience. This provides a basis for critique of new well designs and a means of assessing the impact of changes to the design.

Details of the model are provided in the paper together with examples from the field development which illustrate how the model has been used. The paper also presents how the model has been used to understand sensitivities and identify where improvements can be made to a well design to improve the probability that screens can be run successfully. The technique used to develop the model will be applicable to other multivariable complex drilling and completion problems.
Comparison of Booking Methodologies for Production Sharing Agreements and Service Contracts
Authors: Reiter Doris F. , Bolling John D.
Published: December 2007

Concessions were predominantly used up until the late 1960s, when Production Sharing Agreements- or also called Production Sharing Contracts (PSA or PSC) - came into existence. They provide an alternative to concessionary systems for those foreign countries, whose constitutions stipulate that all mineral rights lie with the state, but who do not wish to exploit their hydrocarbon resource base on their own. Regulations, which govern the external oil and gas reserves reporting, give a high degree of latitude as to how a company interprets and applies those rules to reserve bookings. From a financial point of view, PSAs and concessions are quite similar; they are distinctly different though from a philosophical point of view. The concession owner holds title to the hydrocarbons in place, whereas in the PSAs the entitlement is not transferred to the contracting party. But it is the entitlement to reserves, which ultimately provides the right to book reserves. For concessions, the reserve booking procedure is very clear, since the concession owner owns the mineral rights, whereas in case of PSAs the situation gets much more complicated. This paper explores different types of such agreements. It further discusses the question, whether reserve bookings for internal and external reporting purposes are permissible under certain kinds of arrangements and what, if any, volumes can be booked. Two methods are applied: The working interest method and the economic interest method. The hazard in using the working interest method, lies in the fact, that the government production entitlement would be treated as a tax expense from the contractor’s point of view. But the host government or their representing oil institution will book their share of profit oil/gas as well, leading to reported gross reserves exceeding those ultimately produced. It would be preferable if oil companies strive to apply the economic method uniformly. The economic interest represents the actual barrel entitlement and thus is comparable to reserve numbers from concessions or leases.

As the investment community places great significance on reported volumes to gauge the company’s financial strength and future growth potential, it would be desirable to achieve a higher degree of consistency in reserve booking industrywide. Internally the company will profit by improving benchmarking in portfolio management decisions.
Geostatistical Modeling of Facies and Fractures of the San Juan Formation and Reservoir Modeling for Delineation of Orocual Field, Venezuela
Authors: Porjesz Róbert , Vargas Marielis , Guerini Agostino , Márquez Pascual , Melendez Luis , Smith Richard W.
Published: December 2007

The Orocual field is located in northern Monagas State of Venezuela and is owned and operated by Petroleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela. This paper presents the results of the geological and geostatis-tical modeling aspects of an integrated study for the San Juan Reservoir in Orocual Field, Eastern Venezuela. The objective of this work was to establish a static model to be used in dynamic modeling to determine development potential, risk, and hydrocarbon reserves. Special interest exists in untested but highly prospective areas.

A recently acquired 3-D seismic volume was integrated with a detailed core based sedimentology study used to define the depositional environment and facies connectivity. Based on this description, the San Juan Formation is subdivided into 3 major sedimentological units: Lower, Middle and Upper. A stochastic method was used to quantify model uncertainty. The fine grid geostatistical model was up-scaled to provide facies consistency for reservoir modeling. The prediction of heterogeneous fractured reservoir was added to the complexity. Numerical simulation was performed and will be discussed.
A Method for Enhancing the Vertical Resolution of NMR Logs
Authors: Sigal R. F. , Miller D. L. , Galford J. E. , Cherry R. , Day P. I.
Published: December 2007

The vertical resolution of continuous, multi-frequency NMR logs largely depends on the length of the stacking interval. Several factors determine the stacking length, such as the number of Carr-Purcell-Meiboom-Gill (CPMG) echo trains that are stacked to improve signal-to-noise ratio, the time interval between individual CPMG events, and logging speed. Standard processing requires stacking of phase-alternate pairs of CPMG events to remove "ringing" contributions. "Ringing" lumps together the non-formation signals present in the acquired CPMG echo trains. This requirement imposes a minimum stacking length for any combination of CPMG sequences. If additional stacking is required to improve signal-to-noise, the simplest filter design requires multiples of the minimum stacking interval. This may produce a better signal-to-noise-ratio, and a larger degradation of vertical resolution than is necessary.

An alternative single echo-train offset removal method (SETOR) has been developed to improve the vertical resolution of NMR logs. In this method the ringing contribution is estimated and removed from the individual CPMG echo trains before stacking. In many cases, results with significantly better vertical resolution, compared to the standard processing, can be obtained because the minimum stacking interval is reduced to a single CPMG event. This allows the stacking interval to be tailored to a desired signal-to-noise ratio. The application of the technique is particularly important for the latest nine-frequency tools that are capable of logging at greater speeds than previous tools.

The theory and current implementation of SETOR is described. In addition, a log example is presented to demonstrate how the method can significantly improve vertical resolution. In this example, stacking length could be reduced from 8.5 feet to 3 feet producing a porosity log that closely matches the finer scale features of a conventional density porosity log. Station data are also presented to help validate the method.
A New Method for Assessing the Impacts of Small-Scale Solvent Supply Variations within the Prudhoe Bay Miscible Flood
Authors: Weaver J. W. , Ra J. W.
Published: December 2007

As the Prudhoe Bay Miscible Gas Project (PBMGP) approaches its fourteenth year of operation, the water alternating gas (WAG) flood is facing new challenges. These challenges typically involve projects that lead to small miscible injectant, or solvent, supply variations. For example, upgrades of the surface facilities can increase the solvent supply available to the PBMGP. Conversely, undertaking new EOR projects or supplying solvent to non-Prudhoe Bay projects will reduce the supply available to the PBMGP.

To accurately assess these projects, a new methodology was developed for forecasting enhanced oil recovery (EOR). This methodology provides increased ease of use and greater reliability in assessing small changes in solvent supply when compared with direct application of large-scale models.

Full-field modeling of miscible injectant (MI) allocation and enhanced oil recovery for the Prudhoe Bay WAG flood is currently performed with large scale-up models. While these models are excellent for evaluating large, full-field decisions related to miscible injection at Prudhoe Bay, they can yield ambiguous results when used to evaluate projects that cause small solvent supply perturbations. The difficulty in resolving the impacts of small incremental projects is a common weakness of large-scale reservoir models.

Through analysis of numerous Prudhoe Bay full-field simulations of large variations in the MI supply, it was found that a two-component analytical equation was excellent for fitting the character of the cumulative EOR impact. The logarithmic function represents the ultimate EOR impact of a change in MI supply, whereas the Weibull function represents the EOR oil rate acceleration (or deceleration) component. The optimum coefficients for the composite analytical equation were found through regression of large-scale simulation results.

This paper documents the methodology used to create the analytical equation as well as the equation's successful testing. The methodology could be applied to other large-scale models that suffer from an inability to accurately evaluate small incremental projects.
Optimization of Well Placement in a Gulf of Mexico Waterflooding Project
Authors: Guyaguler Baris , Horne Roland N. , Rogers Leah , Rosenzweig Jacob J.
Published: December 2007

Determination of the location of new wells is a complex problem that depends on reservoir and fluid properties, well and surface equipment specifications, and economic criteria. Various approaches have been proposed for this problem. Among those, direct optimization using the simulator as the evaluation function, although accurate, is in most cases infeasible due to the number of simulations required.

In this study a hybrid optimization technique based on the genetic algorithm (GA), polytope algorithm, kriging algorithm and neural networks is proposed. Hybridization of the GA with these helper methods introduces hill-climbing into the stochastic search and also makes use of proxies created on the fly. Performance of the technique was investigated on a set of exhaustive simulations for the single well placement problem and it was observed that the number of simulations required was reduced significantly. This reduction in the number of simulations reduced the computation time, enabling the use of full-scale simulation for optimization even for this full-scale field problem. It was also seen that the optimization technique was able to avoid convergence to local maxima due to its stochastic nature.

Optimal placement of up to four water injection wells was studied for Pompano, an offshore field in the Gulf of Mexico. Injection rate was also optimized. The net present value of the waterflooding project was used as the objective function. Profits and costs during the time period of the project were taken into consideration.
Simulation Model Development for Bayu-Undan Field
Authors: Currie J. C. , Balke S. C.
Published: December 2007

A case study is presented showing how reservoir characterization with geostatistical modeling was used to develop the reservoir flow simulation model for Bayu-Undan Field. The modeling was tailored to both reservoir type and the selected development scenario.

Bayu-Undan Field is currently under development as a gas recycle project with future gas export. The reservoir is made up of both fluvial and marine sedimentary sequences. The need to predict fluid flow for both recycle and depletion scenarios in the presence of these reservoir types requires an understanding of reservoir heterogeneity and a method to preserve it in an upscaled flow simulation model.

The major control on reservoir character is facies type which controls grain size, sedimentary structure and degree of bioturbation. Facies were determined from log motif and core description. Different statistical techniques were chosen to build facies models for the continuous marine zones and the heterolithic marine/fluvial zones. Numerous facies realizations were constructed to evaluate the possible range of outcomes and uncertainties. Porosity was distributed either deterministically using a weighted average algorithm or statistically using variograms. Permeability was distributed using a porosity-based transform.

A number of permeability upscaling algorithms were evaluated to ensure reservoir heterogeneity was preserved when upscaling from the geocellular model to the flow simulation model. As a result, separate algorithms were chosen for horizontal permeability in marine and fluvial units, and for vertical permeability. Use of these upscaling techniques resulted in very good preservation of gas in place by permeability class, shown by comparing the geocellular model with the upscaled model. The modeling captured and preserved the reservoir flow characteristics critical to performance predictions for the gas recycle project.
State-of-the-Art Nonphosphate Design Revolutionizes Hydrocarbon-Based Completion Technologies
Authors: Thompson Joseph E. , DeVine Carolyn S. , Delorey John R.
Published: December 2007

Oil based fluids have been used since the inception of well completion technologies. Formation sensitivity to water has often been the primary consideration for the selection of oil based stimulation fluids. Historically, oil based fracturing designs required complicated procedures to successfully execute a fracturing operation. Rheological properties of fluid compositions used did not produce stimulation fluids with optimum viscosity or transport characteristics. The obvious hazards involved in accomplishing an operation using these types of fluids were also great due to the variability of the fluids caused by different base hydrocarbons.

The development of a unique system with rheological, transport, and process advantages, which have long been desired in hydrocarbon based stimulation fluids are discussed in this paper.

In addition, the chemical evolution of the oil based gel system will be discussed, and properties of the fluid including rheology, break, and conductivity testing will be presented. Characterization of the rock mineralogy for those formations which can be considered as candidates for stimulation with the hydrocarbon based system are presented. Detailed field case histories of the application of the new system are included. In general, stimulation with the new system provides a rapid clean-up and return to production.
A General String Design Method for Extended-Reach and High-Pressure Applications
Authors: Zheng Andrew S.
Published: December 2007

This paper presents a general string design methodology that optimizes coiled tubing (CT) string makeup for extended-reach and high-pressure applications. The string design methodology includes three components, namely tubing force, pressure limit, and wall-selection criteria. The wall-selection criteria qualify the use of a given wall thickness for the string based on the consideration of string ratings and extended-reach potential, which relies on a new parameter called "compression ratio (η)". Through the analysis of tubular lockup behavior, the compression ratio is found to govern the lockup depth of tubing string in wellbores. Integrating the calculations of tubing force and pressure limit with the compression ratio-based wall selection criteria optimizes string makeup by minimizing the overall tubing weight while satisfying the requirements of string ratings and extended-reach. Design examples for both extended-reach and high-pressure applications demonstrate the effectiveness of this method.
New Methods for Estimating of Formation Pressures and Fracture Gradients from Well Logs
Authors: Draou A. , Osisanya S. O.
Published: December 2007

The accurate prediction of pore pressures and fracture gradients has become almost essential to the drilling of deep wells with higher than normal pore pressures. Drilling costs and problems can be reduced substantially by the early recognition of abnormally high pore pressures.

Two new methods have been developed from well logs that can be applied universally to the determination of pore pressures and fracture gradient. The first method uses the principle of compaction concept where the porosity varies exponentially with vertical stress, and the second method uses the power-law relationship. Acoustic logs obtained from five wells in Ouargla and Garet El Bouib fields are used to validate the two methods.

The computed pressures matched the measured pressures obtained from repeated formation tests (RFT). The deviation between the first method and RFT varies from 3% to 6%, while, the deviation for the second method varies from 1% to 3%. The acoustic log predicts fluid pressure within an accuracy of 0.05 psi/ft. The standard deviations for the first method and the second method are 0.04 psi/ft and 0.02 psi/ft respectively. The analysis also shows that there are two overpressured zones in the well studied, which accurately matched the actual sequence of events while drilling the wells. The developed methodologies are illustrated and validated with several examples from the Hassi Messaoud field in Algeria.
A Real-Time Well Site Log Analysis Application Using MRI Logs
Authors: Aadireddy Prabhakar , Coates George
Published: December 2007

With any complex logging tool, there exists a need for a "qualitative and reasonable" analysis, run in real-time at the well site that both provides a preliminary interpretation of the data and also serves as a means for enhancing quality control. Such an application has been developed to provide a quicklook analysis of data from NUMAR’s MRIL® -Prime tool.

The application takes advantage of the Prime tool’s ability to simultaneously acquire data from multiple nuclear magnetic resonance (NMR) activations for purposes of fluid identification. The application is based on several well-established NMR fluid-characterization methods. These methods compute total porosity, effective porosity, bulk volume irreducible, flushed-zone fluid volume, and fluid type in a variety of reservoirs. The methods used in quick-look analyses include the Differential Spectral Method (DSM™), Time Domain Analysis (TDA™), Shifted Spectrum Method (SSM™), Enhanced Diffusion Method (EDM™), and the Total Porosity Method (TPM™).

Accomplishing these objectives, i.e., computation of total porosity, effective porosity, etc., in a real-time environment requires consideration of the wellsite engineer’s level of experience and responsibilities. In addition, the dynamics of the real-time wellsite analysis presents several competing and important challenges: acquiring quality measurements, working with limited data and information, and providing results in a timely and efficient manner. Thus, a real-time analysis should be robust and consistent with any additional analysis done in the post-acquisition environment.

A set of procedures has been developed to guide the process so that reasonable interpretations can be obtained over a broad range of operating conditions. To simplify the engineer’s tasks, the analysis procedure is automatically driven by the type of NMR data being obtained. Thus, meaningful results can be obtained without increasing the burden on the field engineer.

This paper briefly describes the techniques that have been developed and demonstrates their application through field examples.
Development of a Robust Gyroscopic Orientation Tool for MWD Operations
Authors: Estes R. A. , Epplin D. M.
Published: December 2007

The allure of a gyroscopic directional sensor for MWD (Measurement While Drilling) operations has spanned over two decades now. The authors first investigated potential sensors for MWD applications in 1982 and were disappointed to find technological limitations precluded such a device. Why is it so difficult to build a gyroscope into an MWD tool, and why don't we have one available for commercial use in the industry today? Also, what should oil companies expect from a service company who promises an "MWD Gyro Tool" in the next year or two?

Currently there are several service companies working on directional modules that incorporate some type of gyroscopic sensor and promise to provide an indication of "True North" direction in conjunction with MWD tools. This paper is intended to establish realistic expectations for the performance that might be delivered by these early gyroscopic tools in the harsh MWD environment.

The paper also describes the investigation, specification, design decisions, and testing done in the development of a tool to meet the most common application requirements for an MWD Gyro. Initial testing of the tool has proven it surprisingly accurate and at least as robust as existing conventional mag/accel sensors. Extensive qualification testing in both lab and field settings has proven the instrument capable of surviving the harsh MWD environment.
An Improved Empirical Approach for Prediction of Formation Water Saturation and Free Water Level for Uni-modal Pore Systems
Authors: Negahban Shahin , Gunter G. W. , Smart C. R.
Published: December 2007

Minimizing the uncertainty associated with the prediction of formation water saturation can be achieved through the integration of formation evaluation (log analysis), capillary pressure data, and pressure gradient information. To reduce the uncertainty, it is often necessary to determine porosity, permeability and water saturation using integrated methods. The magnitude of uncertainty reduction associated with predicted petrophysical parameters is a function of the inherent quality of the various data acquisition devices. Thus, reduced uncertainty in hydrocarbon pore volume can often be achieved by combining explicit probabilistic formation evaluation and a quantitative capillary pressure model.

An empirical quantitative capillary pressure-water saturation model has been developed that relates the capillary pressure and height above the free water level, FWL to the wetting phase saturation. This relationship generalizes the correlation for all existing rock types that exhibit uni-modal pore geometries. The model constants are expressed as continuous functions of the interval speed that is defined as the square root of core measured permeability divided by porosity (√k/ϕ) data. The water saturation is calculated continuously as a function of the height above the FWL using the log predicted permeability-porosity ratios. In the absence of a clear fluid contact, the new model provides an excellent tool for describing the fluid contacts by iterating on saturation. The FWL is adjusted until a good agreement exists between a base water saturation and the predicted water saturation from the empirical capillary pressure relationship.

This paper describes the new saturation model and its application for a siliclastic layered reservoir. The model parameters are tuned based on a statistically significant number of measured high-pressure mercury injection capillary pressure curves. Furthermore, the model parameters are calibrated to data from a key well. The results of the model are then used to predict formation water saturation in neighboring wells.
Density Measurements Of Cement Sheaths Provide Accurate Evaluation Of Oil Well Cementing Operations
Authors: Cocanower R.D. , Dillingham Mat E. , Reeves Chet
Published: December 2007

Publication Rights Reserved

This paper was prepared for the 38th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in New Orleans, La., on October 6–9, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to published is hereby restricted to an abstract of not more than 300 words, with no Illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary. Such abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request providing proper credit is given that publication and the original presentation of the paper.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Laboratory and field results have proven the use of density measurements of the cement sheath to provide more information than other methods to evaluate oil well cementing in relation to the well program. Skips, channels, voids, and low density slurries are accurately detected from density measurements. This knowledge compared to the type of completion or rework program desired will assure the engineer of a successful program.

A flux of collimated gamma rays directed into pre-set weights of solids and solutions, adjacent to casing, has produced an adequate spread of points that is relative to the bulk density of these materials. The phenomenon of backscattering affected by compton scattering, photoelectric absorption and the mechanics of the sonde has made this possible. Test pit and field data revealed the required mechanics to narrow the zone of inspection to borehole dimensions only.

Since the amplitude of the recorder response is subject to bulk density changes of the mass adjacent to the casing, then the result will show the uniformity or the non-uniformity of the solids or solutions in this area. Contamination by a foreign material decreases the cohesiveness of the cement slurry, therefore it reduces the adhesiveness of the cement to casing and adherence of cement to formations.

Interpretation of the density curves is easily made by engineers or operators. Typical logs from various areas are shown to support the laboratory development data. The information obtained is a valuable aid lo interpreting neutron logs and chlorine logs as shown by case histories.
Evaluation of Risk in Appraisals of Large-Scale Development Projects for Financing Purposes
Authors: Miller Richard J.
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Large scale projects for the development of new oil and gas fields, whether in the U.S. or foreign, are often financed by commercial bank lending. Particularly when such financing is Particularly when such financing is done on a "project" basis on appraisal of the property to be developed is required for a lender to determine the future value and debt repayment ability of the property. Such appraisals are often performed prior to development with data from a few exploratory wells. These appraisals can have results that vary greatly depending on the methods of data application.

This paper presents a system of engineering appraisal which combines statistical methods of data application with commonly used reservoir engineering procedures. Data distributions on procedures. Data distributions on such componants of the reservoir and production appraisal as porosity, production appraisal as porosity, permeability, and gas-oil ratio are permeability, and gas-oil ratio are used to identify ranges of potential appraisal results. Statistical methods of frequency distribution and standard deviation are used to obtain a distribution of final appraisal results. The system then uses a variation of expected value theory to impose a risk factor on the appraisal results to determine the expected value of future reserves and revenues from the project. This appraisal procedure allows the lender to assess risk exposure and to structure the project financing accordingly.

Introduction

Over the past 30 years oil and gas exploration and development has moved continuously from the relatively inexpensive and safe continental areas to more remote and challenging areas. A very rapid expansion of large scale development has occurred offshore and in previously undeveloped areas. The primary example is the North Sea but offshore California, Alaska, Arctic Canada and the Amazon Basin are also very active. In the North Sea alone more than 20 new fields have been discovered and are in various stages of development. The cost of development of these new areas is enormous. The large number of extremely high cost projects undertaken by all companies has resulted in massive bank debt financing.
Coping With Another Embargo: Evaluating the Effects and the Economics of Reducing the Impact
Authors: Dutton Granville
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The Arab Embargo of 1973–74 reduced U.S. liquid petroleum supplies by less than 10%, yet — coupled with panic legislation and regulations — panic legislation and regulations — resulted in severe supply dislocations, great inconvenience to most Americans and actual hardships for others. Today, an effective OPEC embargo could reduce liquid supplies by 40% and would disrupt a substantial segment of the American economy as well as seriously curtail the individuals' freedom to travel and drastically reduce the nation's standard of living.

This paper details the geographical areas and industries that would be most adversely affected by another embargo. The effects on the standard of living, as measured by the Gross National Product and the reduction in the number of jobs, are calculated. It is concluded that the results of such an embargo would be unacceptable to the American people.

Alternatives to military action are presented in the form of an analysis of available domestic energy resources, the state of the technology utilized in converting these resources to usable fuels, the time necessary to bring on additional supplies in meaningful quantities, the required capital investment and the prices necessary to generate such investments. Finding that the alternative, although subject to an appreciable time lag, is technically and economically feasible, the restraints hindering the timely development of adequate domestic energy sources are investigated.

These restraints are found to be primarily economic and environmental, primarily economic and environmental, including restricted access to public lands. Although they arise from actions of the public, environmental zealots, alleged consumer advocates, regulatory agencies and the judiciary, their efficacy stems from legislation and their elimination and/or reduction is shown to be dependent upon the legislative process. A method whereby those with expertise and interest in solving our energy process can effectively influence this process is presented.
A Simplified Utility Framework For the Analysis of Financial Risk
Authors: Cozzolino John M.
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The von Neumann-Morgenstern utility (risk-preference) theory is the most consistent and comprehensive theory of risk. Yet it has been used very little for representation of financial risk problems. Instead, special purpose methods of risk representation have purpose methods of risk representation have been used. The goal of this paper is to propose a simplified utility framework. Three different possible axioms are considered. They all possible axioms are considered. They all uniquely imply that the utility function must be of the exponential form. It appears that this simplified utility framework will be more fruitful than other special purpose methods for risk representation. A two-stage method of risk analysis is recommended and an example from oil exploration is shown.

Introduction

An axiomatic, consistent representation of risk can lead to simple models that convey much insight. Such a foundation is the von Neumann-Morgenstern theory of utility (risk preference). This concept of risk is relative to preference). This concept of risk is relative to an individual decision maker. It is assumed that the individual's fundamental measure of wellbeing is his quantity of wealth. Thus, the argument of an individual's utility function is his wealth. This assumption commonly is made in treating financial problems.

The goal of this paper is to develop a simplified utility framework that trades off some of its generality to gain ease of solution for practical risk problems. The method is to assemble many well known facts into a comprehensive picture of the properties of exponential utility functions.

Following Pratt's notation, let x represent total wealth at the initial time. Let U(x) represent the individual's utility function for wealth at the end of the period. It is assumed that U(x) is continuous and possesses second derivatives. Let z represent the profit or net return (increment to wealth) during the period. Then the terminal wealth will be x + z period. Then the terminal wealth will be x + z at the end of the period. The profit is a random variable at the initial time. It has a probability distribution with density function probability distribution with density function f(z). This probability distribution may be discrete or continuous. However, without loss of generality, the notation of continuous random variables will be used.

At the initial time the individual's utility position is the expected utility of terminal wealth:~E {U(x+z)} = U(x+z)f(z)dz ...........(1a)
Increasing Eastern U.S. Natural Gas Reserves from Gas Bearing Shales
Authors: Overby William K.
Published: December 2007

The U. S. Energy Research and Development Administration (ERDA) has initiated a multi-year project directed toward the stimulation of project directed toward the stimulation of natural gas production in the Eastern Petroliferous basins. The objective of the project is to stimulate increased commercial production of natural gas by providing reliable resource data, developing economical extraction alternatives, and demonstrating the commercial feasibility of promising production techniques. The project promising production techniques. The project should provide a significant contribution to the domestic energy base, supply a clean fuel for eastern industrial use, and help to alleviate anticipated near-term and long-term shortages of natural gas.

The ERDA Eastern Gas Shales Project will be oriented specifically toward determining the true magnitude of potential gas reserves in the Devonian Age Shale, thoroughly characterizing the shale, and evaluating and improving state-of-the-art gas exploration and extraction technology. Results will be continually evaluated to determine areas in which new or additional studies may be needed and the desirability of planning and conducting a more extensive research, development, and demonstration (R, D and D) program. The project will concurrently monitor program. The project will concurrently monitor and protect the environment from possible damage resulting from natural gas development activities.

The project envisioned consists of the major elements listed below.An inventory of the natural gas resource and recoverable reserves contained in the Eastern Shales.A characterization of the nature of the shales in the three major sedimentary basins in the east (Appalachian, Illinois, and Michigan).The development of exploration methods for locating fractured shale and other gas reservoirs associated with shale.The performance of research and development studies on methods for improving gas recovery from the shales.The implementation of a concurrent Field-Test Program to transfer the concepts in exploration, drilling, stimulation, and production to the natural gas industry.The performance of environmental assessments to assure acceptable environmental impacts from exploratory and demonstration activity.The performance of economic analyses to indicate commercial viability of various options.
Fracture Investigation of the Devonian Shale Using Geophysical Well Logging Techniques
Authors: Myung John L.
Published: December 2007

Publication Rights Reserved Publication Rights Reserved This paper is included in the Proceedings of the 1976Appalachian Petroleum Geology Symposium on Devonian Shales. It is reprinted here with Petroleum Geology Symposium on Devonian Shales. It is reprinted here with permission of the Geological and Economic Survey of the State of West permission of the Geological and Economic Survey of the State of West Virginia. Publication elsewhere is hereby restricted to an abstract of not more than 300 words, without illustrations, unless the paper is specifically released for publication by the copyright holder. Such abstract should contain appropriate conspicuous acknowledgment.

Conventional well logs and interpretation methods do not provide sufficient information to evaluate the productive gas zones of the Devonian productive gas zones of the Devonian shale in the Appalachian area. The major gas accumulations are believed to occur in fracture systems in close proximity to the source beds. With proximity to the source beds. With this premise in mind, an approach to locating and evaluating the fractures and showing evidence of the source beds has been formulated.

The approaches to evaluating the fractures in the shale are discussed as follows:Empty Borehole Logging Program and Computer Data PresentationSeisviewer SurveyApplications of the 3-DVelocity Log

EMPTY BOREHOLE LOGGING PROGRAM AND COMPUTER DATA PRESENTATION

The empty borehole logging program to evaluate the shale formation program to evaluate the shale formation is extremely important since most operators are concerned about washouts and caving caused by filling the borehole with fluid. The Devonian shale is particularly sensitive to voter. The following should be considered an essential empty borehole logging program with currently available logs:

Gamma-Ray Log Formation Density Log Induction Log Temperature Log Sibilation Survey

Since conventional interpretation techniques using the above combination of logs do not provide a conclusive result in identifying potential pay zones in shale, a new potential pay zones in shale, a new concept and technique directed toward evaluating potential productive zones has been employed.