bluuebunny/crossref_metadata_2025 huggingface dataset:
Type-Curve Analysis Using the Pressure Integral Method
Authors: Blasingame T. A. , Johnston J. L. , Lee W. J.
Published: December 2007

This paper presents new type curves and type curve plotting functions which use integration rather than differentiation of well test data. These functions provide more unique type curve matches for noisy data because the integral of these data yields a much smoother function. The type curves presented in this work were generated from analytical solutions and are applied in exactly the same manner as in conventional type curve analysis.
A Numerical Approach to the Diagnosis of Sucker Rod Pumping Installations and its Verification with Downhole Pump Field Measurements
Authors: Chacin J. E.
Published: December 2007

Most current diagnostic techniques that stablish downhole conditions from polished rod measurements, are based on simplified analytical solutions and thus have inherent limitations. In the present investigation these limitations are fully explored and a new diagnostic approach, based on the method of characteristics, is introduced in order to overcome said limitations. This new approach is more flexible (since it can be easily extended to include deviated and directional wells), allows the estimation of computational error, yields a more accurate downhole load estimation and compares very favorably with state-of-the-art codes.

A specially designed Downhole Instrumentation Unit (DIU) was used to obtain downhole measurements (at the, pump) in a test performed in a 5625 feet deep rod pumped well. The DIU is a microprocessor based 5 feet long "intelligent sucker rod" that can be screwed in anywhere along the rod string. The results of this test show that the diagnostic technique using the method of characteristics provides a very good estimation of actual loads along the rod string and at the subsurface pump.
The Effect of High-Density Perforating on the Mechanical Crush Resistance of Casing
Authors: King G. E.
Published: December 2007

A series of tests to describe the effect of numerous holes in casing on the mechanical crush resistance has been run in casing and in L-80 steel tube models. The tests were run with big holes and normal hole sizes for perforations in phasings of 0°, 180°, 120°, 90°, and 60°. Shot density was varied in the model tubes from 4 to 36 shots per foot. The actual perforated casing was at 12 shots per foot. All of the perforated casing and tubing sections were compared to strength remaining in unperforated pipe of the same specimen.

The tests were carried out in a compression machine under a controlled rate of loading with strain gauges attached at critical points along the plane of expected failure. The casing and tube specimens were loaded between steel platens. The data for the test are plotted in the form of load vs deflection. Strain gauge data are also presented. The information generated includes observations of the effect of entrance hole size, phasing (lateral hole separation), shot density (linear hole separation at a specific phasing), and effect of the position of the plane of perforations to the plane of application of load.
Improved Productivity from Low-Pressure Gas Wells Through the Utilization of Wellsite Compression
Authors: Neal H. L.
Published: December 2007

The deliverability of Amoco operated wells in the four main fields in the Arkoma Basin has been improved by the installation of wellsite compression. The compressor candidates were identified by a compressor simulation test. A study investigated the economics of purchasing versus leasing a wellsite compressor. Compressors were installed and the success of the installation depended on the initial sizing parameters used and the reservoir characteristics. Several operational improvements evolved which enhanced the profitability of these installations.
The Impact of Fracturing Fluids on Conductivity and Performance in Low-Temperature Wells
Authors: Thomas R. L. , Brown J. E.
Published: December 2007

A study investigating the performance of low temperature wells following hydraulic fracturing is presented. Emphasis is placed on proper fracturing fluid and breaker selection to minimize proppant damage and maximize fracture conductivity. The study indicates borate crosslinked fluids yield minimal damage whereas organometallic crosslinked fluids consistantly yield severe damage. A detailed discussion of the impact of fluid-induced proppant damage on well performance is given.

Although previously reported laboratory work has addressed the topic of in-situ fracture conductivity, the results of conductivity damage in wells with low bottomhole static temperatures have not been reported. A detailed discussion of extensive laboratory conductivity testing at 100 ° F is presented to address the issue of conductivity impairment (damage) in low temperature wells. The conductivity and permeability of Jordan sand placed with several fluids incorporating various crosslinkers and breaker systems is reported. The data indicate crosslinked fracturing fluids can be used in low temperature wells to yield high fracture conductivity. However, the amount of damage observed is a function of both the crosslinker and breaker system.

Subsequent to laboratory testing, the impact of the fluid/breaker system on the performance of oil and gas wells was evaluated. Numerous fracture design and production simulations were performed to evaluate the effect of fluid systems on well performance. These data indicate production can increase 50% or more simply by incorporating a "cleaner" fracturing fluid system.

In conclusion, fracturing fluid and breaker selection are variables that must be considered when designing a fracture treatment in a low temperature well. This study indicates proppant placed with a borate crosslinked fracturing fluid containing a persulfate/amine breaker exhibits minimal conductivity impairment resulting in improved well performance.
The Effect of Speed Variation on the Operating Range of Submersible Pumps
Authors: Kobylinski L. S.
Published: December 2007

A manufacturer must consider several factors when setting a particular pump's recommended operating range. Limits may be based purely on the wear life limitations of the pump thrust washer or on a predetermined minimum acceptable efficiency or head. Other factors must be considered in setting operating limits, including the need for sufficient fluid flow to allow for motor cooling and avoiding vibration induced by operation at very high or low flow rates. Operation at near shut-off conditions will cause localized overheating, particularly of the thrust washers resulting in excessive wear and premature failure.

This paper discusses pump axial thrust and pump thrust washer limitations. Tests were performed to determine actual values of pump thrust and washer wear. A series of curves showing a pump "operating range" based purely on axial thrust considerations are included.
Algorithm for More Accurately Predicting Nitrogen-Charged Gas-Lift Valve Operation at High Pressures and Temperatures
Authors: Winkler H. W. , Eads P. T.
Published: December 2007

The published nitrogen temperature correction factors (Ct) are used to calculate the change in bellows-charge pressure with temperature. If these Ct-factors are used to calculate the test rack opening pressures for the gas lift valves in a high operating injection gas pressure system, the error in the temperature correction may prevent successful gas lift operations. An accurate correlation for calculating the changes in nitrogen pressure with temperature is presented in this paper.
Analysis of Well-Testing Data from a Restricted-Entry Well
Authors: Ding W. , Onur M. , Reynolds A. C.
Published: December 2007

This work investigates the analysis of well test pressure data from a restricted-entry well using pressure and pressure derivative type curves constructed from constant-rate solutions. For cases where wellbore storage effects are negligible, it is shown that type curves constructed from constant rate solutions can be used to analyze rate data from wells producing at a constant bottom-hole pressure and that these type curves can also be used to analyze data obtained from gas wells. For cases where data are influenced by wellbore storage and skin effects, it is shown that a new analysis procedure using complete-penetration type curves based on dimensionless pressure and a dimensionless pressure/pressure derivative group can usually be used to obtain a complete analysis of data. The analysis procedures presented yield estimates of horizontal permeability, the mechanical skin factor and the vertical permeability.
Inhibitor Treatment by Coil Tubing Unit Can Now be Performed While Maintaining Production
Authors: Going W. S.
Published: December 2007

A new chemical injection valve run on coil tubing allows inhibitor treatment of well tubing without interruption of well production. Chemical injection is controlled at the surface by hydraulic pump pressure and flow rate to provide uniform distribution along the entire tubing length. The inhibitor is discharged into the production stream and will rapidly deposit onto the tubing wall. The valve is deployed with existing coil tubing service equipment and a minimum of additional tools.

The Coil Tubing Inhibitor Valve is a back pressure regulator. The valve design is based on a state-of-the-art side pocket mounted chemical injection valve for wells completed with a continuous inhibitor system. The valve mechanism consists of a nitrogen biased piston directly connected to the valve stem. The piston has integral metal-to-metal seal cups that are sized to the cylinder bore for exceptional sealability. A redundant elastomer seal complements the rugged all-metal seal design. Inhibitor fluids discharging from the valve strikes a high speed turbine which breaks-up the discharge stream into a radially directed spray completely encircling the turbine. This discharge pattern provides 100% tubing wall coverage as the valve is moved upwards through the well.

Typical batch inhibitor treatment methods require production shut-in periods. With tubing displacement from surface treatments, the lost production period often includes an extended recovery time for the well to return to pretreatment production rate. With the coil tubing injection valve the cost of treatment is offset by incremental production compared to treatments that require that the well be shut-in. The precise metering of chemicals over the target interval reduces the overall chemical cost by reducing over treatment and wasted chemicals.
Identification and Treating of Downhole Organic Deposits
Authors: Addison G. E.
Published: December 2007

Cost-effective oil production of wells that are known to have a history of downhole organic scale deposition is possible when a program of identification, testing, and chemical application is correctly instituted. Stimulation of production can result if there is available crude and pressure in the formation being bottled up by organic scale deposits. Removal of these "roadblocks' will allow the migration of additional crude. It is much cheaper to remove the roadblock, instead of building new roads, i.e., fracturing.

There are two different types of organic deposits or scale. One is composed primarily of paraffin and the other of asphaltenes. Both paraffin and asphaltenes are natural constituents of most crude oils and their presence is not necessarily a cause for alarm. Only if the well seems to have problems is an investigation warranted. With the different constituency of the deposits comes the requirement to treat them in a different manner.
Acquisition Strategy Development
Authors: Caldwell R. H. , Heather D. I.
Published: December 2007

Analysis of consummated U.S. based oil and gas acquisitions in terms of price paid for a given reserve magnitude yields fundamental conclusions. The historical price paid can be directly correlated with the then current wellhead price and also with the outlook for the future. Separating transactions into principally oil versus principally gas, yields separate correlations and is the main cause of difficulties when averaging $/BOE data.

Acquirers can be subdivided into groups that operate in defined "acquisition territories," such territories having economic, legal and physical boundaries. By defining acquisition territory, the likely competition mix and price usually paid can be modelled based on an analysis of past transactions. This knowledge is invaluable in both strategy formulation and in bid price estimation.

This analysis documents historical acquisition trends (based on over 600 transactions) and performs basic correlations with price, industry sector, and business cycle position. This data provides correlations for development of predictive models and hence the ability to tailor acquisition/divestiture strategy to the ever-changing business environment.
Risk Analysis in Hydrocarbon Appraisals
Authors: Gustavson J. B. , Murphy D. J.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.
A Study of Bacteria-Influenced Scale Deposition
Authors: Reeves N. K.
Published: December 2007

Scale deposition in perforations and tubular goods has been a problem for decades in the oil industry. Years have been spent in research and in somewhat futile attempts to solve this problem. Classic treatment is with a fluid, usually an acid, which is designed based on the mineralogical content of the scale. Complicating these efforts is the relationship of down-hole bacteria to scale deposition. The above mentioned treatments do not address the presence of bacteria. The ability of organisms to thrive in hostile environments is sometimes difficult to overcome and the number of biocides on the market today attests to this. The problems caused by these scale deposits have cost producers millions of dollars and have been known to change sweet oil to sour in whole fields. Also, much money has been spent for cathodic protection and other corrosion inhibition treatments when the major cause of tubular corrosion may have been biological activity.

Typical scale identification consists of determination of constituents by chemical means, X-ray or microscopic analysis, and acid solubility tests. This series of tests is necessary for the design of scale removal treatments, but does not account for the causes of scaling. Computer programs which determine the scaling tendency of waters give an insight into the cause of scaling. However, none of these tests can show the influence of biological activity. In order to provide a more thorough analysis of the cause of scaling, the use of epifluorescence microscopy has been added to the testing scheme. Bacterial cells from a scale and/or water are dyed and their fluorescence observed microscopically. The lack of fluorescence indicates no biological activity. The information gained from this microscopic technique is then used to modify removal treatments and to design treatments to help prevent further deposition.

This paper will discuss (1) epifluorescence as a scale testing technique, (2) well conditions that contribute to bacterial growth, (3) areas in the Rocky Mountains where bacterial scaling is prevalent, and (4) removal and inhibition treatments.
Rate-Cumulative Type Curves for Forecasting the Performance of Curtailed Wells
Authors: Lewis P. E. , Hoff J. G.
Published: December 2007

Most gas wells in the U.S. have not consistently produced at or near capacity in recent years due to persistent excess deliverability in the gas market. Seasonal or erratic production history can wreak havoc with traditional well performance forecasting techniques. Rate-time forecasting methods generally depend on the assumption of capacity production throughout the life of the well. Distortion caused by curtailment can be reduced somewhat by plotting rate vs. cumulative flowing time, but flowing time is not always available, and more importantly, distortion is still present on both the rate and time axes.

The fundamental problem with rate-time history matching is that stabilized production capacity is not a function of time, rather, it is a function of reservoir pressure which is a function of cumulative production.

History matching with rate-cumulative type curves presented here eliminates curtailment induced distortion on the cumulative (X) axis. The rate-cumulative approach is more accurate for "real world" situations where only production per period is available (e.g. Mcf/month). Unlike rate-time curves, the proper rate-cumulative curve match will always represent stabilized producing capacity, regardless of shut-in periods.

Other advantages are that rate-cumulative type curves allow the engineer to read forecast ultimate reserves for any given abandonment rate graphically from the match, stabilized deliverability may be easily forecast at any given cumulative production, and cumulative production is inherently smoothed data.

Dimensionless rate-cumulative type curves were generated by integrating rate-time type curves developed by Hale1 for fractured gas wells draining

an elliptical area. The original type curves were based on infinite conductivity fractures, but the technique can be extended to finite conductivity fractures.
Type Curves for Predicting Production Performance From Horizontal Wells in Low-Permeability Gas Reservoirs
Authors: Duda J. R. , Aminian K.
Published: December 2007

Type curves have been developed for horizontal wells producing from low permeability gas reservoirs. The general solutions are presented in terms of dimensionless cumulative production and dimensionless time and are grouped based on two other dimensionless variables, the wellbore radius and well length.

The type curves were developed using the solutions to flow problems, which were determined using a finite-difference reservoir model. This paper includes a detailed account of the methodology used and comparisons of supporting simulation results to other, general flow solutions that have been previously reported. Issues concerning the production performance of horizontal wells in anisotropic media are also discussed. The curves can be used to initially predict the performance of horizontal wells, thus avoiding the need for costly and time consuming computer simulation.
A Simulation Study of Horizontal, High-Angle, and Vertical Wells in Eastern Devonian Shale
Authors: Zammerilli A. M.
Published: December 2007

This study is a comparative evaluation of predicted gas production from horizontal, high-angle, and vertical wells in the tight, fractured Devonian shales of West Virginia. The optimal drilling method was determined by economic and production comparisons of simulation results from studies of unstimulated and stimulated wells of the following types: a single horizontal well, a single high-angle well, and up to four vertical wells. Infill drilling was compared to new-lease wells, and the effect of faulting on predicted gas production was studied. The study showed that new-lease horizontal drilling is the optimal method in West Virginia, and high-angle drilling results in a slight improvement over vertical drilling. Horizontal drilling showed as much as a 46 percent improvement in production performance over both vertical and high-angle drilling for new-lease wells. Economically, a single 2,000-ft (6.096 × 102 m) horizontal well revealed a ROR of 40 percent and payout of 1.6 years as compared to 11.2 percent, 4.9 years and 4.1 percent, 7.8 years for single new lease vertical and 60° high-angle wells, respectively.
Well Spacing Analysis By The Discounted Production Method
Authors: Dehn Bren C. , Stoy Thomas W.
Published: December 2007

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This paper is to be presented at the 36th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in Dallas, October 8–11, 1961, and is considered the property of the Society of Petroleum Engineers. Permission to publish 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 acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the Journal of Petroleum Technology or Society of Petroleum Engineers Journal is granted on 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.

The Discounted Production Method of analyzing well density is a means whereby the increase in the discounted net profit by acceleration of a reservoir's depletion can be calculated for each succeeding development well. With the generalized equation, the actual accelerated reserves, and hence the discounted net profit, can be computed for any contemplated development well, for any interest rate, for any type of declining or constant production, and for any initial and final production rate.

This method has utility in that, it is a quick means of attaining the correct answer as to the number of wells that a pool should have in order to be properly developed by present worth standards. It also affords a ready comparison of discounted net profit and discounted profitability from potential development investments in different pools.

Introduction

After the exploration phase has passed and an oil pool is considered to be well enough defined to enter its development era, the problem is, how many additional wells are necessary to deplete the reserves. Although an inherent and Important part of this period is assuring that a maximum amount of oil be recovered from the reservoir, proper drainage of the oil is not the only consideration of those concerned with the economics of a development program.

What then constitutes proper development? In the days prior to mineral conservation commissions, proper development might have consisted of merely drilling as many wells as there was room for on a particular tract of land, or it might have consisted of enough wells to deplete the reserves in a given period of time that was considered to be a standard reservoir life.
Parameter Accuracy Required for Real-Time Fracture Geometry Simulation
Authors: Elbel J. L.
Published: December 2007

A major goal in hydraulic fracturing research is to be able to determine the fracture geometry, based on measurements of the treatment parameters, during the actual performance of the treatment. The treatment parameters measured are injection rate, viscosity of fluid and bottom-hole treating pressure; and, of these, the last two are difficult to obtain accurately under normal treating conditions. This paper provides equations and graphs that indicate the effect that an error in each parameter will have on the real-time fracture length calculation. These can be used to determine the parameter accuracy required and also indicate when real-time simulation will be practical and on what parameter (viscosity or pressure) it should be based. In fracture geometry simulation, it is assumed that the magnitude of the parameters are known. A number of papers have shown the effect of various parameters on fracture length. However, the effect of an error of an individual parameter is dependent on its magnitude in relationship to the magnitude of the other parameters. This paper shows that the effect of an error of a parameter on the fracture length calculation is a function of treatment efficiency. Therefore, if the treatment efficiency can be assumed or determined from an injection test, the effect of an error on any parameter can be determined. Simple algebraic equations and plots are given showing the effects of errors in each parameter as well as the error in more than one parameter.
Boundary-Dominated Flow in Solution Gas-Drive Reservoirs
Authors: Camacho R. , Raghavan R.
Published: December 2007

In this work the performance of wells in solution gas-drive reservoirs during the boundary-dominated flow period is examined. Both constant wellbore pressure and constant oil rate production modes in closed systems are considered.

For the constant wellbore pressure production mode, the conditions under which procedures in the literature can be used to analyze data are discussed. Specifically, Arps's equations for performance prediction are examined and it is shown that predictions of future performance are strong functions of well spacing, well condition, and fluid properties. The parameters, b (the decline exponent) and di (the initial decline rate), in the Arps equations are expressed in terms of physical properties. The conditions under which these equations can be used are specified. An empirical procedure to predict production rates is also presented.

In the case of constant oil rate production, an expression to correlate the pressure distribution in the reservoir is presented. The correlating function permits us to extend the definition of pseudosteady- state flow to solution gas-drive systems. Its use also allows the simultaneous computation of average properties (pressure and saturation) during boundary-dominated flow from wellbore information.