bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Measurement and Analysis of Circulating System Pressure Drops with Low-Toxicity Oil-Based Drilling Fluids
Authors: Minton R. C. , Bern P. A. 
Published: December 2007

Abstract
The ability to predict accurately the circulating system pressure drop whilst drilling is a prerequisite of drilling optimisation. The quantification of the annular pressure drop is also necessary to calculate the equivalent circulating density of the drilling fluid. With invert emulsion drilling fluids, using ‘low toxicity’ paraffinic oils, these calculations are complicated by the viscosity changes under downhole conditions.
This paper presents data from three separate hole sections where annular and drill string pressures were continuously monitored using Measurement While Drilling (MWD) instrumentation. Readings were taken between 2625 and 14764 ft (800 and 4500m) with mud densities ranging from 9.33 to 11.67 ppg (1120 to 1400 kg/m3). The data are summarised and tabulated with respect to the hole geometry, circulating rates and drilling fluid properties.
The derivation of correction factors for the estimation of the drilling fluid rheology at elevated temperatures and pressures is detailed with results of laboratory studies using HP/HT viscometry.
The theoretical pressure drops through the annular and drill string sections, with and without application of the rheology correction factors, are then presented. Two rheological models are employed, the power law with yield stress (Herschel-Bulkley) and the Bingham model.
The theoretical pressure drops are compared with the actual values. The application of the rheology correction factors is discussed and the comparative merits of the two models reviewed.
Finally the paper discusses the implications of the research to hydraulics planning and identifies critical areas of development required to enhance the predictions.
A Case History of Dewatering and Recycling Sump Drilling Mud on 141 Wells in the Midway Sunset Field, California
Authors: Nordquist D. G. , Faucher M. S. 
Published: December 2007

Abstract
Significant savings have been realized at the Midway Sunset (MWSS) Field in Kern County, California through dewatering and recycling sump drilling fluid, thereby eliminating mud "disposal" costs and liabilities. A dewatering unit was introduced at MWSS in October, 1986, in an effort to reduce the high disposal cost of sump fluid. Disposal cost for non-hazardous liquid had risen from $10.10/bbl in October, 1986, to $16.40/bbl in May, 1987. Mud disposal cost represented 15% to 20% of the cost to drill and complete a MWSS well. Dewatering and recycling sump drilling mud reduced this disposal cost to $3.49/bbl and, thereby, lowered drilling costs by $ll,621/well (average). Continued utilization of this process on 141 wells drilled from October, 1986, through September, 1987 generated a savings of $1,638,561.
Modification of the Cullender and Smith Equation for More Accurate Bottomhole Pressure Calculations in Gas Wells
Authors: Oden R. D. , Jennings J. W. 
Published: December 2007

ABSTRACT
The modification of the Cullender and Smith equation presented here consists primarily of adding a gas-water ratio term, and a friction factor term as given by the explicit Jain-Swamee correlation. The results of this study show a reduction in the average error in predicting bottom-hole pressure of 3.4 percent for the flowing cases and 1.9 percent for the static case when the modified Cullender and Smith equation was used instead of the original Cullender and Smith equation.
This study resulted in two major conclusions. First, modification of the Cullender and Smith equation produces a more accurate method of calculating static and flowing bottom-hole pressures. Second, using an apparent roughness of 0.0023 inches instead of an absolute roughness of 0.0006 inches will further reduce the RMS error for the flowing case.
An Investigation To Improve the Accuracy of Calculating Bottomhole Pressures in Flowing Gas Wells Producing Liquids
Authors: Rendeiro C. M. , Kelso C. M. 
Published: December 2007

ABSTRACT
A method is presented for calculating flowing bottomhole pressures in gas wells producing liquids. This method, a refinement of the Average Temperature and Pressure Method, includes an adjustment to the gas gravity to account for the presence of well stream liquids and the use of an optimum absolute roughness in the calculation of the friction factor. The effect of dividing the wellbore into multiple segments was also investigated.
The proposed method was tested against 144 wells obtained from a paper by Peffer et. al.1 Of the wells tested, 94 were originally from a paper by Govier and Fogarasi.2 The other 50 wells were taken from the files of the Texas Railroad Commission.
Definitive CO2 Flooding Response in the SACROC Unit
Authors: Langston M. V. , Hoadley S. F. , Young D. N. 
Published: December 2007

ABSTRACT
A substantial increase in oil production resulting from CO2 flooding has been clearly identified in two multi-pattern areas of the SACROC Unit. Analysis of the two areas permitted the identification of oil response to CO2 injection with greater accuracy than has previously been possible at SACROC. The areas include the 600 acre [2.43×106 m2] Four Pattern Area (4PA) and the 2700 acre [10.93×106 m2] Seventeen Pattern Area (17PA). Located in the Kelly-Snyder Field of Scurry County, Texas, the 50,000 acre [202.3×106 m2] SACROC Unit is the world's largest CO2 miscible flooding project.
The 4PA encompasses 24 wells arranged in four contiguous inverted 9-spot injection patterns. The area has been on pattern waterflood since 1972 and was at a 95 percent producing water cut when CO2 water-alternating-gas (WAG) injection was commenced in June 1981. An approximate 30% hydrocarbon pore volume (HPV) of CO2 was injected over a 5-year period at WAG ratios ranging from two to eight. CO2 injection ceased in May 1986 and the area has been on continuous water injection since that time. Incremental oil recovery attributable to CO2 injection is estimated currently to be at least 9% of the original oil in place (OOIP). This represents an estimated cumulative CO2 utilization, of 9.5 Mft3 per barrel of incremental oil [1692 m3/m3].
Also on pattern waterflood since the early seventies, the Seventeen Pattern Area has exhibited an approximate 5% OOIP recovery after injecting 17% cumulative HPV CO2·CO2-WAG flooding in the 17PA began in May 1981. Currently, the cumulative CO2 utilization is estimated to be 9.7 Mft3 per barrel of incremental oil [1728 m3/m3].
This paper examines the methods used to determine CO2 mobilized oil response, describes how the effects of workovers and other "normal" field operations were accounted for, and evaluates the influence of activities in patterns adjacent to the study areas.
Cedar Creek Anticline Carbon Dioxide Injectivity Test: Design, Implementation, and Analysis
Authors: Good P. A. , Downer D. G. 
Published: December 2007

ABSTRACT
The eighty mile [130 km] long Cedar Creek Anticline structure, trending from eastern Montana to southwestern North Dakota, contains at least a dozen carbonate reservoirs at an average depth of 9000 feet [2745 m]. All of the major oil accumulations have been under waterflood, starting from the mid-1950's to the mid-1960's. These waterfloods are now reaching a mature stage.
Laboratory PVT, core flood studies, and field measurements of waterflood residual oil saturation indicated that there was potential for carbon dioxide floods in the Cedar Creek Anticline water-flood units. A three well carbon dioxide injectivity test was initiated in 1983 in the South Pine Field to define carbon dioxide injectivity and extent of tertiary oil mobilization for the important Red River U4 interval.
The test consisted of an injection well, a logging observation well, and a pressure/sampling observation well. The three bottom hole locations were within 90 feet [27.4 m] of each other. The injection sequence was to inject twelve percent brine, a carbon dioxide slug, then resume the twelve percent brine injection. Pressures were monitored continuously in the injection well, the pressure/sampling observation well, and a passive offset well 650 feet [198 m] from the test location. Detailed surveillance of fluid movement in the test area was obtained by frequent monitor logging using compensated neutron, induction and gamma ray logs. A post-flood pressure core was cut to measure the oil saturation remaining after the carbon dioxide slug injection.
Analysis of pressure measurements indicate the observed carbon dioxide injectivity was approximately fourteen times that of the preflood brine. Log and core measured saturations show substantial desaturation of waterflood residual oil in the well swept areas of the test interval; mobilized tertiary oil was also produced at the pressure/production observation well, located 70 feet [21.3 m] from the injector. The detailed analysis of fluid movement during the test has been complicated by the heterogeneous nature of the test interval at the location of the pilot. Flow horizons within the U4 with permeability contrasts on the order of a factor of fifty have been identified through analysis of brine tracer and carbon dioxide encroachment data. Pressure transient data, thermal front arrival times, brine tracer data, carbon dioxide and follow-up brine encroachment data, and tertiary oil desaturation log and core measurements were analyzed to obtain an estimate of the values of parameters needed for estimation of full scale flood response.
Placement of Gels to Modify Injection Profiles
Authors: Seright R. S. 
Published: December 2007

ABSTRACT
This study investigates how flow profiles in injection wells are modified when zones are not isolated during placement of gelling agents. Mathematical models are used to examine the degree of gel penetration and injectivity loss in zones of different permeability. Several conclusions are drawn that apply to reservoirs in which crossflow between layers does not occur. First, zone isolation is far more likely to be needed during placement of gels in unfractured wells than in fractured wells. Productive zones in unfractured wells may be seriously damaged if zones are not isolated during gel placement. Second, gel placement without zone isolation should cause the least damage to productive zones in unfractured wells when (a) the gelling formulation exhibits a low resistance factor during placement, (b) the water-oil mobility ratio is relatively high, (c) the most-permeable layer(s) are watered-out, and (d) the waterfronts are not close to the production well in the productive zones. Third, parallel linear corefloods overestimate the degree of profile modification that can be attained in radial systems. Fourth, chemical retention, dispersion and diffusion will probably not significantly mitigate injectivity losses caused by gel penetration into low-permeability zones. Finally, a need exists to determine the permeability and velocity dependencies of gelling-agent resistance factors and of gel residual resistance factors.
Tracer Surveys To Identify Channels for Remedial Work Prior to CO2 Injection at MCA Unit, New Mexico
Authors: Beier R. A. , Sheely C. Q. 
Published: December 2007

ABSTRACT
A tracer program to identify channels within the Grayburg/San Andres formations prior to CO2 injection has been performed and analyzed at the Maljamar Cooperative Agreement (MCA) Unit. For safety and costs reasons two separate interwell tracer surveys or phases were conducted. In the Phase 1 tests tritium was injected into 62 wells through injection headers to identify field areas where channelling occurs. Within 12 weeks, 25 out of 177 producing wells sampled had a response. Tritium was used because it has a larger acceptable response window between its minimum detectable level and the maximum safe peak response than other available radioactive tracers. This first survey provided important design information for the second survey which included tracers with smaller response windows. The Phase 2 tests included the 19 producers with the larger Phase 1 responses and their 27 active offset injectors. With the use of multiple tracers, the Phase 2 tests identified 14 problem injection wells as channelling sources. Unexpectedly, the source of some channels was farther away than the nearest offset injectors. In addition, the two tracer surveys showed that tracer flow is sensitive to changes in operating conditions. Thus, every reasonable effort should be made to perform tracer surveys under normal operating conditions.
Field Testing of a New Conformance-Improvement-Treatment Chromium(III) Gel Technology
Authors: Sydansk R. D. , Smith T. B. 
Published: December 2007

ABSTRACT
Field testing results are reported for a new conformance-improvement-treatment (CIT) gel technology, where acrylamide polymers are crosslinked with a chromium(III) [CrIII] crosslinking agent. Results are reported for nine field tests performed in Wyoming's Big Horn Basin during 1985 and 1986. All nine treatments were designed to reduce conformance problems encountered in naturally fractured reservoirs. Seven were injection-well treatments, and two were production-well treatments. All nine field tests were operational and technical successes.
Significant amounts of incremental oil production were obtained following five of the seven injection-well field tests and at both production-well field tests. Peak incremental-oil-production rates resulting from the injection-well gel CITs ranged from 38 to 380 bbl/D [6.0 to 60 m3/d]. The first production-well field test, in a carbonate reservoir, generated 7500 bbl [1190 m3] of incremental oil (beyond 4400 bbl [700 m3] of projected base oil production). The second production-well field test, in a sandstone formation, required a smaller than expected gel volume. The second treatment has generated over 14,000 bbl [2200 m3] of incremental oil and did pay out in five months.
Overall, the economics of the field testing program are encouraging. For the seven field tests which stimulated incremental production, incremental stock-tank oil production through May 1987 was 450,000 bbl [71,500 m3]; and the production wells affected by these seven gel CITs were still producing at a combined incremental-oil-production rate of 780 bbl/D [124 m3/d] above pretreatment decline rates. Cost of the seven field tests (including well workover, gel, and gel injection costs) totaled $438,000, yielding a cost for incremental stock-tank oil production through May 1987 of .97/bbl [$6.10/m3].
The field testing program has shown that the new gel CIT technology can generate significant amounts of incremental oil production profitably, even during times of depressed oil prices, and can be used to significantly reduce water/oil ratios (WORs). Field testing has also shown that the gel technology is operationally attractive. At all nine field tests, quality CrIII gel was made consistently and injected without encountering any significant operational, safety, or environmental problems. Little, or no, chromium was detected in associated produced fluids. As intended, significant reductions in injectivity occurred during all the injection-well field tests. The field tests demonstrated that large volumes of gel can be injected into the cited fractured Big Horn Basin reservoirs.
Evaluation of a Surfactant: Steam-Soak Pilot Test in the Bolívar Coast, Venezuela
Authors: Robaina R. M. , Maraven S. A. , Ziritt J. L. 
Published: December 2007

Abstract
This paper presents field test results of sixteen steam soaked wells in which the injected steam was treated with two different surfactants selected in the laboratory as being the most suitable to be applied under Bolívar Coast Conditions. The laboratory research was done by Shell Laboratorium (Netherlands) and Intevep-PDVSA Research Center (Venezuela) and the main selecting criteria was the pressure drop measured in the porous media during steam foam flow tests.
The two steam foam formulations selected were, a long-chain alkyraryl toluene sulphonate (SURFACTANT 1) and a branch-chain alkyraryl benzene sulphonate (SURFACTANT 2). The SURFACTANT 1 was used in nine wells while the SURFACTANT 2 was injected in seven.
The stimulation mechanism of SURFACTANT 1 seems to be steam diversion to the less produced sands and for SURFACTANT 2 it appears to be a change of interfacial properties in the water-oil-rock system.
Although most of the steam foamed wells had not completed the production cycle, it can be concluded that 60% of them have presented positive response to steam foam. The initial oil rate response was equal to or slightly greater than that expected from a normal cycle; but steam foamed wells produced up to three times the additional cumulative oil expected (75,000 bls vs. 25.000 bls for a third cycle). This is due to the fact that the decline of the oil production rate was lowered to about 12% pa. which is indeed close to that of primary production.
The better oil production performances were obtained when the steam penetrated deeper into previously non productive layers. The maximum diversion registered was close to 90 feet as compared to 35 feet of the initial profile.
Modeling Transverse Imbibition in Double-Porosity Simulators
Authors: Beckner B. L. , Firoozabadi A. , Aziz K. 
Published: December 2007

ABSTRACT
Published imbibition experiments of an advancing fracture water level surrounding a single matrix block are simulated using various double porosity models. These double porosity formulations are inherently unable to represent transverse imbibition with an advancing water level in the fracture as they are based essentially on one dimensional flow. Gross matches of the experimental and double porosity simulations required shape factors that were unrepresentative of the matrix block size. Increasing the fracture water injection rate required increasing the shape factor in order to achieve gross matches, hence a constant shape factor does not give the best matches with experimental data at different rates.
A new double porosity transfer function for transverse imbibition is presented based on a nonlinear diffusion equation model for imbibition and the effective exposure time of elements of the matrix block to fracture water. This formulation uses the physical dimensions of the matrix block directly, i.e. no shape factor, and was effective in matching the experimental data without tuning any parameters.
A comparison of a cubical single matrix undergoing fracture waterflooding was made between the various double porosity formulations and a fine grid, single porosity simulation. The conventional double porosity simulations did not this fine grid simulation as well as the proposed double porosity formulation.
Hole Enlargement Control During Arctic Drilling
Authors: Kutasov I. M. , Caruthers R. M. 
Published: December 2007

ABSTRACT
A number of problems occur during Arctic drilling: hole and surface instability, and poor cementing jobs intimately associated with washed out formation. During drilling the formation is heated by circulation of a warm drilling fluid. As a result, the strength of soils around the well is significantly reduced by the melting of ice. Heating of frozen soils without thawing also sharply reduces the shear strength of soils and results in the caving of frozen soils. In this paper the results of analytical and experimental investigations are presented which show that the diameter of washouts depend on properties of drilling muds and soils, temperature, flow rate and duration of mud circulation. An experimental study of washouts in frozen soils (a model of a borehole was used) has shown that fluid infiltration into the thawed zone plays a dominant role in hole enlargement. This study shows that the size of washouts can be significantly reduced. Some practical recommendations are proposed for drilling operators.
Improving the Steam Drive: Physical Model Studies of Inert Gas Injection and Horizontal Wells
Authors: Doscher T. M. , Ying A. , Kostura J. A. 
Published: December 2007

SUMMARY
Scaled physical model studies were undertaken to illustrate the following matters: 1) the advantage of using high velocity gas injection for recovering reservoir fluids, 2) the injection of gas and steam, after steam breakthrough, for increasing the profitability of some steam drives, and 3) the use of specially fractured horizontal wells to aid in the profitable production of very viscous hydrocarbons.
The conduct of this work was supported by a Small Business Incentive Research Grant from the U.S. Department of Energy. Patents covering most of the findings were formulated following former laboratory studies and studies of field operations in China, Venezuela, Canada and the United States.
OPEC's Current $18/Barrel Price Policy: Its Rationale, Member Country Economic Consequences, and Future Implications
Authors: Naraghi M. 
Published: December 2007

ABSTRACT
The increasing oil market share strategy, orchestrated by the Saudis in late 1985, brought about the most precipitous decline in oil prices in the history of OPEC within a very short time period. The major implication of this exercise, contrary to prevailing conventional wisdom, was that there existed a short run price elasticity of demand for OPEC oil, of substantial magnitude and effectiveness. The immediate task faced by OPEC was to implement a market clearing oil price strategy that:
would balance the member countries' current economic utility, would effectively represent the marginal cost of crude oil production by non-OPEC producers, would curtail substitution of other competing fuels (gas, coal, nuclear, etc.)
The present paper, in applying the short run oil supply elasticity algorithm to the actual crude production and price data globally, postulates the possible rationale behind OPEC's nearly unanimous decision to maintain the crude oil price at the $18/B level. Furthermore, in analyzing the incremental revenue vector for the member countries at various prices, and by scrutinizing the OPEC countries' current account deficits, it is illustrated why the Saudis, under the current quota system, are extremely reluctant to increase the oil price from the $18/B- $20/B range, in the short term; while most other members would like to see the price in the $25/B-$27/B range. Finally, expected medium term (1988-1992) and long range (1993 and after) scenarios for crude oil prices are outlined.
New Materials Improve the Cementation of Salt Formations in the Williston Basin
Authors: Whisonant B. J. , Rae P. J. , Ramsey L. K. 
Published: December 2007

Abstract
Massive salt sequences have posed numerous cementing problems over the years. Many additives, designed for use in fresh water based slurries, display poor performance when placed in very saline environments. Other additives, designed primarily for use in very saline environments, have less than optimum performance and exhibit detrimental side effects to other slurry performance properties.
This paper discusses the problems posed when cementing through these salt sequences, current practices to deal with the problems, and describes the benefits of new materials which provide superior performance in high-salt slurries. Field case histories are included from the Williston Basin to illustrate field utility.