bluuebunny/crossref_metadata_2025_split huggingface dataset:
Risk Analysis in Hydrocarbon Appraisals
Authors: Gustavson J. B. , Murphy D. J. 
Published: December 2007

ABSTRACT
Since the presentation in 1984 of the author's paper on "Comparison of Methods for Determining Fair Market Values," (SPE Preprint 13769), the authors have had an opportunity to evaluate the risk analysis methods used both by industry as well as by their own firm in over thirty appraisal cases. The industry cases were further analyzed as part of the class work in the University of Tulsa-sponsored seminar on "Appraisal of Oil and Gas Properties," where critical review by many market sector representatives was applied. With these data as a base, a study has been made of the adequacy (or lack thereof) of the risk analysis in oil and gas property appraisals. It has been found that of the four methods generally used by industry for fair market value determination, only one adequately addresses risk analysis and allows numerical treatment of the subjective part of the appraisal. We term this method the Risked Present Worth method, while the other three are generally known as the Β0Ε method, the Cumulative Cash method and the Targeted ROR method. None of these latter three methods, while frequently used, allows for a systematic approach to risk analysis.
In contrast, the Risked Present Worth method provides for a distinction between the effects of time-value-of-money and the mechanical, operator and market-related risks. In the continuing development of this method over the last four years, it has become possible to develop checklists for subjective assessment of the various types of risk toward determination of a single risk factor which subsequently can be multiplied into the unrisked present worth of the future cash flow and yield an acceptable fair market value. These checklists are designed to allow risk analysis by appraisers of varying levels of skill or experience. They are also designed to provide default values where some details about an oil or gas property may be unavailable. The method currently defaults (if absolutely no information is available) at a risk factor of 0.73 for proved developed producing properties as of fall, 1988. Additional market data evaluations performed during the preparation of this paper show a slight downward trend toward 71%. The detailed risk analysis, which can be performed on the basis of additional property information, may increase or decrease the risk factor. Under current economic conditions (winter, 1988), the present worth at 10% would be used as a base for the unrisked present worth, but could be accurately adjusted to reflect the prevailing interest rates.
OPEC Production and Crude Prices: Review and Outlook
Authors: Roberts M. L. 
Published: December 2007

ABSTRACT
The quantum jumps in oil prices that took place during the 1970's set in motion certain irreversible forces that have changed the structural demand for energy. The 28% decline in energy demand per real GNP among the seven major industrialized countries (65% of the Free World's energy consumption) over the past fourteen years suggests that economic growth has been decoupled from the historical 1:1 ratio with energy consumption. Re-enforcing this view are the resultant negative elasticities (ratio the percent change in demand to the percent change in price) of 0.38-0.55 between the years 1973 and 1985. In 1980, a methodology was developed employing the concept of price elasticity and economic growth to ascertain the future demand pull on OPEC reserves and ultimately the direction of crude oil prices (See SPE paper 11314 dated March, 1983).
A review of the methodology utilizing actual 1985 data indicates that the matrix of economic growth versus percent change in energy demand per real GNP has relatively strong predictive value. This review will be the first subject of discussion in the paper.
The second part of the paper employs the same model in an attempt to forecast the demand pull on OPEC production, OPEC capacity utilization, and the expected price for crude in the early 1990's. However, the precipitous decline in oil prices in 1986 now suggests a slightly negative to positive elasticity and a possible turnaround in declining demand for OPEC crude.
If OPEC can exercise production discipline and act as the world's swing producer to balance the oil supply-demand, there appears to be a good chance in the early 1990's for oil prices to stabilize at the $18.00-$20.00 per barrel level, with the call on OPEC crude production reaching levels near 80% of OPEC productive capacity, up from the current level of 64%.
FERC Orders and the Evolving Natural Gas Market
Authors: Dancy J. R. , Yard D. F. , Dancy V. A. 
Published: December 2007

ABSTRACT
The natural gas industry has quickly changed from one which was dominated by long term contracts between the producer and pipeline to one that is characterized by contracts of much shorter duration. Part of the reasons for this change are economic, and part are due to the changing regulatory structure surrounding the industry.
Over the last ten years the number of natural gas wells in the United States has steadily increased, from around 144,000 in 1977 to around 240,000 in 1987. See: Figure 1. While the number of natural gas wells has steadily increased the total amount of natural gas reserves in the United States has remained relatively constant. See: Figure 2. As a result, the reserves attributable to each natural gas well has declined from 989 MMcf per well in 1977 to around 588 MMcf per well in 1987. See: Figure 3.
Valuing Oilfield Investments Using Option Pricing Theory
Authors: Lehman J. 
Published: December 2007

ABSTRACT
Traditional investment analysis, which accepts investments when the discounted values of their expected future cash flows are positive and otherwise rejects them, is generally incorrect because of its inability to adequately account for the uncertainty of future oil prices and the capacity of managers to take actions in the face of those changing prices. Oil companies often attempt to deal with this problem through the application of techniques ranging from price sensitivity analysis to complex decision analysis or dynamic programming techniques with varying degrees of success. The objective is to value the investment managed, in some sense, optimally over time, as the future environment is revealed. Such techniques may address the shortcomings of more simplified approaches, but are at best extremely cumbersome and at worst impossible to perform correctly. This paper illustrates the shortcomings of the traditional approach to investment analysis as well as a particularly sophisticated variant, dynamic programming, and offers option pricing as an alternative analytic technique.
Success Rates and Reserves in the Hardeman Basin of Texas
Authors: Swindell G. S. 
Published: December 2007

ABSTRACT
North Texas′ Hardeman Basin contains a number of prolific Mississippian carbonate oil fields discovered mainly in the last ten years. A statistical study of reserves and success rates has been made of nearly all the wells drilled in Hardeman County, including the shallower formations. The study shows the primary Mississippian objectives have a current success rate of 18% and will average 169,500 bbl (26,948 m3) per well; uneconomic at present oil prices and costs.
The Economic Potential of Strategic Infill Drilling in the San Andres/Grayburg South Central Basin Platform Play
Authors: Godec M. L. , Tyler N. 
Published: December 2007

ABSTRACT
This paper summarizes the results of a larger study assessing the economic potential of extensive infill drilling in the San Andres/Grayburg, South Central Basin Platform Play.1 The study provides estimates of economically recoverable crude oil and associated gas from infill drilling in 19 West Texas carbonate fields contained in the play. A detailed geologic and engineering analysis was conducted on a specific 640-acre section of the Dune Field (Section 15), which was considered to be representative of the fields in the play and was used for evaluating the potential infill recovery in the analyzed reservoirs. Estimates of recoverable oil and associated gas were contrasted for reductions in well spacing from 80 acres to 10 acres per well, using a uniform or "blanket" infill drilling program compared to a geologically targeted, "strategic" infill drilling program.
The results indicate that, due to reservoir heterogeneity, significant volumes of oil and gas are economically recoverable through extensive infill development in the play. Geologically targeted drilling significantly improves project economics and dramatically lowers the threshold oil price required to support project implementation. The results indicate that cost-effective infill development of existing oil and gas fields will increasingly rely on interdisciplinary solutions requiring the expertise of both petroleum geologists and engineers to maximize recovery and economic viability.
Financing Opportunities for Small- and Medium-Size Oil and Gas Companies
Authors: Huggins N. J. 
Published: December 2007

Abstract
It is no secret to anyone in this room that the oil and gas industry is a capital intensive one - the participants in which usually rely heavily on the financial markets to fund expansion plans. Unfortunately, as regards the capital markets, oil and gas companies have faced a kind of "double indemnity" in recent years - the volatility of the oil and gas business itself combined with the dramatic volatility of the financial markets over this same period. Needless to say, October 19, 1987, redefined the term volatility for all of us vis-a-vis the equity market, but the debt markets have exhibited their own version of volatility as evidenced by experience over 1988. For example, the ten-year Treasury bill has fluctuated from a low of 8.10% in February, 1988 to a year high in the 9-1/2% range - a roughly 150 basis point fluctuation that would have been unheard of only a few years ago in the course of a single year. As always, though, the flip side of challenge has been opportunity, and any number of small, medium-sized, and large oil and gas concerns have successfully tapped the markets during this period - not only insuring their survival in a volatile era but also positioning themselves well for the recovery. The secret to success for the energy companies which have financed successfully has usually been timing, product innovation, or often a combination of both.
The Use of After-Tax Investments in Project Evaluation
Authors: Thompson R. S. , Wright J. D. 
Published: December 2007

ABSTRACT
In the evaluation of oil and gas properties, the reserve estimator must forecast the timing of cash receipts and cash expenditures. The cash flows can then be discounted to account for the time value of money. One of the cash flows estimated is the cash tax liability or savings generated by the project. The treatment of these cash flows in project evaluation is investigated in this paper. Two alternatives-using pre-tax investment dollars for the "Time 0" investment and using after-tax investment dollars for the "Time 0" investment, are compared to a more "rigorous" treatment of cash flows. The results show that the use of after-tax investment dollars with mid year discounting consistently results in higher values for some popular managerial indicators than those obtained using pre-tax investment dollars. Both methods give results which are greater than the more rigorous quarterly approach.
Planning and Communication: The Keys to Bank Financing
Authors: Rogers C. D. 
Published: December 2007

ABSTRACT
Bank financing, once a widely used tool of the energy industry, is used much less frequently due to the instability of the oil and gas industry and various problems in the banking industry. Banks will take some calculated risks, but are reluctant to invest in companies or industries which are not fully understood.
This paper is designed to give independent producers a system to bridge the information gap and educate their banker. It allows the producer and banker to evaluate the company's ability to borrow and repay money, and will also help to evaluate the risks incurred at different levels of borrowing. Budgeting from a combination of historical financial information, future drilling and development plans and engineered proved producing properties will provide a hybrid forecast from which educated lending decisions may be made.
Method of Optimizing Memory and Power Usage in a Downhole Memory Recorder
Authors: Richardson J. M. , Duncan R. L. 
Published: December 2007

ABSTRACT
This paper examines the problem of discriminating between linear and nonlinear data regions of measured data as a method of minimizing memory use. Since in oil well production testing, one may expect relatively long periods of linear or nearly linear data, the memory and power savings can be significant. An added dimension of this problem is the trade off to be made between the cost of attempting to discriminate too accurately, thereby storing unnecessary data points (which expends memory space and battery power), and the cost of not discriminating accurately enough, which fails to record data required for accurate analysis. A method of dynamically changing the operating characteristics of the linear discriminator to take into account the amount of remaining memory and battery power is also presented. Classical hypothesis testing was the analytical method used to implement the linear discrimination scheme.
The Combined Effect of Fluid Lag and Fracture Toughness on Hydraulic Fracture Propagation
Authors: Jeffrey R. G. 
Published: December 2007

ABSTRACT
Analytical expressions for the fluid-lag distance in hydraulic fractures have been found by using the weight function method. The fluid-lag distance is the region near the tip or leading edge of the fracture that is not penetrated by the fracturing fluid. Closed-form expressions for fluid-lag distance have been obtained for both KGD-type and penny-shaped fracture geometries subject to driving pressures that were taken to be either uniform or quadratic in distribution. For this analysis, the fluid-lag region is assumed to contain fluid at reservoir pressure.
The analytical expressions provide a convenient way of studying the variation of the fluid-lag distance as a function of the other parameters of the problem. A general nondimensional equation for fluid-lag distance is given that is valid for both of the fracture geometries considered and for all of the pressure loading cases studied. A method of using the results to account for the effects of fluid lag in two- and three-dimensional hydraulic fracture simulators is suggested.
The analytical results have been used to show that the fluid-lag distance in classical KGD-type fractures quickly approaches a constant value while the fluid-lag distance in penny-shaped fractures is a decreasing function of the radius.
Case Study Production Optimization Shunda Rundle B Pool
Authors: Wright B. K. , Hawkes R. V. 
Published: December 2007

Abstract
Following a pipeline deliverability test in December 1986, the contract rates were reduced for two wells completed in the Shunda Rundle B Pool in Western Alberta. A study was subsequently initiated to determine the cause of the substantial decline in deliverability. Initially, it was suspected the wells were experiencing near wellbore damage and that a re-stimulation would improve the wells’ deliverability. A review of the previous massive acid fracture stimulations, the production characteristics, and proper well test analysis techniques showed the wells not to be damaged, but tight and effectively stimulated. The relationship between "flush" production and "stabilized" production has been defined in order that proper economic considerations are understood before any stimulation or re-stimulation treatment is considered in tight gas reservoirs.
Barque and Clipper: Well Test Analysis in Low-Permeability Fractured Gas Reservoirs
Authors: Moore P. J. R. M. 
Published: December 2007

Abstract
Barque and Clipper are two low permeability sandstone reservoirs in the southern North Sea basin. Gas initially in place amounts to some 1800 Bcf (5.1 × 1010 m3), of which 900 Bcf (2.5 × 1010 m3) is presently estimated to be recoverable. The formations are Permian age Rotliegend dunes, which have suffered diagenetic alteration due to palaeoburial, with a consequent sharp reduction in permeability.
From the beginning of appraisal, evaluation of the hydrocarbon resources has been complicated by the heterogeneity of the fields. Observed production rates ranged from less than 1 MMscf/d (2.8 × 104 m3/d) to over 50 MMscf/d (1.4 × 106 m3/d). Conceptually this variation was explained as production from a tight matrix with in situ gas permeability typically from 20 – 40 μd (20 - 40 × 10−6μm2), mediated by a network of natural fractures. Indeed coring has shown natural fractures, of varying cementation, to be present throughout the reservoirs.
During this study, drawdown and build-up data gathered over a 20 year period were critically re-examined applying derivative and classical techniques. Previously unexplained behaviour was shown to result from multiple porosity systems, the incomplete transitions between such systems or hydraulic fracture wall skin. Consequently, it was possible to correlate welltest derived permeabilities to critical point dried and stress corrected core measurements. Finally the geometric average of matrix permeability, calculated from petrophysical measurements, was established as the best estimator of in situ permeability.
The greater understanding of the production processes, resulting from this study, impacted directly on the decision to proceed with the £450 million (US$845 million) development of the Barque and Clipper fields. First gas is due October 1990.
Controlled Pulse Fracturing for Well Stimulation
Authors: Hunt W. C. , Shu W. R. 
Published: December 2007

Abstract
Controlled Pulse Fracturing (CPF) is an emerging technology for stimulation of oil and gas producing formations. The CPF process uses an electrically ignited tool containing a solid propellant charge placed in the wellbore adjacent the zone requiring stimulation. Upon ignition, the CPF tool rapidly generates a high pressure gas pulse. This pulse of gas causes the rock to fracture and generates multiple, short (5-20 ft.) fractures, radiating from the wellbore. These fractures are partially propped by the scouring action of the high velocity gas which transports some of the formation particles down the induced fractures. The stimulated zone is usually contained within 3-6 ft. from the top and bottom of the tool. Another benefit of CPF is the reduction in pressure drop at the wellbore which can reduce solids dropping out of the flowing phase into the pore spaces (e.g., paraffin, scale, etc.) Although hundreds of CPF-type stimulations have been applied in oil and gas wells4,5,6, little rigorous information on the actual success rates is available. Most of the stimulations have been attempted on low rate producers where a valid well test is almost impossible to acquire.7 Very little field data is available on the downhole pressure-time response during CPF stimulations. Also, mechanical aspects such as tool movement in the wellbore are poorly understood. In this paper, we will describe first the basis of the CPF stimulation technique. Laboratory results and field evidence will be presented to validate the theory. Applications of the CPF technique will be outlined. We shall discuss specific field cases on the following applications: 1) Penetrate past near wellbore damaged zones to ensure adequate connection with the formation (i.e. reduce skin), 2) Initiate connection of the wellbore to the zone to allow other stimulation fluids to efficiently and uniformly contact the formation (e.g., acid), and 3) Selectively stimulate isolated parts of a zone either to stay away from water producing zones or even out permeability profiles.
Summary Results of CO2 EOR Field Tests, 1972-1987
Authors: Brock W. R. , Bryan L. A. 
Published: December 2007

ABSTRACT
Since the early 1970s, numerous presentations have been made and articles written about pilot tests and field-scale enhanced oil recovery projects using carbon dioxide (CO2) as a solvent. This paper summarizes publicly available data on 30 projects. The use of CO2 has grown significantly since the early-1980s, especially in the Permian Basin, as reliable supplies of CO2 became more available. Today, even with depressed crude oil markets, the use of CO2 continues to grow. The use of CO2 in the Rocky Mountain region is increasing, primarily among those with prior CO2 flooding experience in the Permian Basin. As the demand for CO2 increases in the Rocky Mountains, so will the supply, and the same growth experienced in the Permian Basin should be seen. As with any major project in the oil industry, the enhanced recovery of oil requires thorough advance planning to determine the optimum EOR method. This summary of CO2 projects is intended to provide a brief on each project, describe the reservoir parameters, and review the conclusions of the individual authors, in addition to providing a quick reference of available papers to which those interested may turn for greater detail. Since the use of CO2 has been successfully tried in a wide range of reservoirs and under a variety of operating conditions, the application of CO2 in Rocky Mountain reservoirs should be every bit as successful as it has been elsewhere.
Cement Solubility in Acids
Authors: Brady J. L. , Gantt L. L. , Fife D. M. , Rich D. A. , Almond S. W. , Ross D. A. 
Published: December 2007

ABSTRACT
Cement solubility in acid has proven to be a problem in the field and has recently been confirmed by laboratory testing. Traditional views have held that acid will react with cement for only a short period of time until it forms a protective skin which inhibits the acid attack. However, field experience has shown that a large percent (≈ 75%) of secondary squeeze cement jobs were breaking down after a HCI-HF acid stimulation. Further, 17% of primary cement jobs developed zonal isolation problems after a HCI-HF acid treatment of the producing perforations.
This paper will document the field evidence from the Eastern Operating Area, (EOA), of the Prudhoe Bay Field, Alaska indicating that HCI-HF acid is damaging to squeezed cement. It will also show from a series of lab tests that cement is quite soluble in several of the various acids used at Prudhoe Bay. HCI-HF acid, the most destructive acid tested, showed a 96% dissolution of a 2×2×2 in. (5.1×5.1×5.1 cm) cement cube when immersed in a stirred solution of 12-3% HCI-HF acid at 190° F. Finally, the data indicates that the major factors that effect the reaction rate are HF acid volume to cement surface area and acid shear rate at the cement/acid interface.