bluuebunny/crossref_metadata_2025 huggingface dataset:
Flow Imaging in Porous Media Using Neutron Radiography
Authors: Jasti J. K. , Lindsay J. T. , Fogler H. S.
Published: December 2007

A new technique is introduced to visualize flow through consolidated porous media. A neutron based computer tomography system is used to inspect a series of laboratory core flood displacements. Two-dimensional advancement of miscible and immiscible fronts were monitored in real time using radial Berea sandstone cores. The effect of the heterogeneity of the core, miscible viscous fingering and immiscible water flooding in sandstone cores have been observed and are discussed. These experiments reveal that neutron radiography has a great potential to study laboratory scale EOR processes. The coupling between flow instability and heterogeneity has been observed for miscible and immiscible flooding. In addition to flow visualization, this technique can also be used to obtain quantitative information such as in-situ oil saturation distribution.
An Approach for the Determination of Economically Optimum Injection and Production Rates in a Large Multi-Pattern Waterflood
Authors: Anthony J. L. , Meggs A. J. M.
Published: December 2007

In a large multi-pattern waterflood, significant improvements in the efficiency of the waterflooding process can be achieved through careful management of the flood rates in each waterflood pattern. Balancing injection and production rates within and between patterns can substantially reduce produced water handling requirements, improve long-term production rates and enhance ultimate recovery. This paper quantifies the impacts of this balancing process and presents a methodology for determining the economically optimum injection and production rates for each well in the waterflood.

Previous work, employing physical models, has investigated areal sweepout behavior as a function of corner to side well producing ratios in a nine-spot injection pattern1, allowing for the determination of ideal producing rates within a single, isolated pattern of homogeneously distributed pore volume. This paper extends the concept of ideal injection and production rates to account for heterogeneously distributed pore volume in a large multi-pattern waterflood.

The deviation of injection and production well rates from ideal values will result from well damage and areal variations in injectivity and productivity. A parameter for measuring the degree to which actual rates vary from ideal rates is developed and correction factors for areal sweepout behavior as a function of this parameter are presented. These correction factors may be used to alter predictions of project-wide performance in order to determine the impact of non-ideal well rates. Examples are included for the determination of the economic incentive for improving production and injection well rates through infill drilling and workovers.
Relative Permeability for Intermediate Wettability Reservoirs
Authors: Heaviside J. , Brown C. E. , Gamble I. J. A.
Published: December 2007

The measurement of relative permeability, essential for the predictive simulation of reservoir response, poses particular problems for rocks of intermediate wettability. This situation is found in many reservoirs for which the well established scaling criteria for cores of well defined wettability no longer hold.

This paper presents results of waterflooding tests on sandstone cores which maintain the intermediate wettability of the reservoirs from which they were sampled. A particular concern was how to characterise displacement for the actual field rates (with the appropriate balance between capillary and viscous forces) whilst avoiding core scale effects which can occur at such low flow rates. Therefore the tests were carried out over a range of flow rates (frontal advance rates from 1 to 100 feet per day) and used both pressure taps and saturation monitoring (1) to obtain distributed data along the cores. Numerical simulation was used to aid interpretation.

The results confirm that displacement in these intermediate wettability cores differs from that in strongly oil or water wet systems in several important regards (a) core scale artefacts ("end effects") are not present even at the low flow rates (b) rate dependencies of relative permeability occur which are due to the microscopic fluid distribution (c) the waterflood displacing shock front is less dispersed at low flow rates, giving increased recovery at breakthrough. Based on these results recommendations are made for relative permeability data for use as input in reservoir performance calculations.
Percolation Theory of Steam/Water Relative Permeability
Authors: Parlar M. , Yortsos Y. C.
Published: December 2007

Thermal recovery and geothermal processes typically involve regimes where the simultaneous flow of water liquid and vapor takes place. Vapor condensation and liquid evaporation are phenomena commonly accompanying such flows. Traditionally, the flow description relies on relative permeability and capillary pressure functions. In contrast to immiscible fluids, however, relative permeability and capillary pressure characteristics of condensing phases are not well understood at present. Instead, the vapor is commonly treated as a non-condensible phase and assigned corresponding flow properties.

In this work, a systematic investigation is undertaken to derive relative permeability and capillary pressure functions for condensible phases, specifically pertaining to a steam-water system. The metnod used is an extension of the approach proposed by Heiba et al1 for immiscible fluids. The novel element is the use concepts from percolation theory for the description of capillary condensation and evaporation processes in porous media obtained elsewhere2. Based on derived analytical expressions saturations and capillary pressure curves are evaluated. Relative permeabilities are next calculated from approximate expressions for Bethe lattices3. The results obtained are compared against those presently used. Implications and extensions to related processes are also discussed.
Cation Exchange Studies on Fractionated Clays
Authors: Fertl Walter , Jessen F.W.
Published: December 2007

Clay containing mono-and divalent exchangeable cations indicate a significantly greater amount of divalent cations on the coarser fractions while monovalent cations are concentrated in the finer ones.

The sequence of replaceability of cations present on the clay sites followed the rule Na >K >Mg >Ca.

A Tektite electrode shows a specific sensitivity to divalent cations and measures the sum of both calcium and magnesium present.

A graphical solution has been presented for determining either the Cation Exchange Capacity [CEC] of calcium or magnesium alone. The chart is valid only if the calcium-to-magnesium ratio in the investigated natural system. is known.

Introduction

The concept of cationic exchange reactions on bentonitic clays [sodium or calcium montmorillonite) is fundamental in many aspects related to drilling muds, well logging and formation properties. Drilling fluid technology has been largely influenced by the chemical reactions of montmorillonite clays. These clays may retain adsorbed cations in an exchangeable state; i.e., a calcium montmorillonite can be converted into a sodium clay, or conversely the sodium, may be replaced by calcium. The basic significance of exchange reactions of montmorillonite in drilling fluids is recognized as an important factor in the rigid requirement of mud properties for drilling deeper and deeper wells. The purpose of this investigation was to develop a method whereby the cation exchange capacity of certain clay fractions, obtained through a fractionation procedure using a supercentrifuge, could be determined through direct titration. Primarily, the study was undertaken to determine the degree of variation, if any, which might exist in the exchange monovalent and divalent cations and clay particle size.

Development of an electrode sensitive to divalent cations was recognized as a vital part of the investigation and the scope of the work was broadened the determine the utility of tektite glass [thin slices of tektite material] as a divalent sensitive electrode. The preparation and use of the tektite electrodes, for the purpose stated, was a distinct objective.

Three different clays were investigated. They represented [1] predominantly Ca++ clays, as in the case of clay No. 4; [2] heterogeneous clays, with Na+ content dominating Ca++ - Mg++ as in clay No. 11 and No. 14; and [3] heterogeneous clays with Ca++ - Mg++ content in excess of Na+ as in the case of clay No. 1. Source of the materials was clay fractions obtained in previous work by Mungan.

Localities and Descriptions

No. 1- Bentonita Blanca Vetessa. Locality:Mexico. Color: beige. Impurities:mostly talc and cristobalite.

No. 4- Bentonita Comisa. Locality: Mexico Color: greyish-white. Impurities:quartz and calcite

No. 11-Bentonita de Durango. Locality: Mexico Color: red-brown. Impurities: large quantity of feldspar and some quartz.

No. 14-Wyoming Bentonite. Locality: Wyoming Color: beige. Impurities: quartz and feldspar.

P. 33^
Drill Fluid and Return Permeability Tests of South Texas Wilcox Cores
Authors: Droddy M. J. , Jones T. A. , Shaw D. B.
Published: December 2007

Core plugs of argillaceous sandstone from the Wilcox Formation of South Texas were examined by petrographic methods and tested for oil permeabilities before and after exposure to a variety of drilling fluids and filtrates. This was done to determine why some drilling fluids are more damaging to permeabilities than others. The clay minerals in these sandstones, which are mostly diagenetic, include chlorite, kaolinite, and pore-bridging mixed-layer illite-smectite. The greatest permeability damage was caused by gelligno-sulfonate-based fluids, which caused pore throat blockage by dispersion and migration of the mixed-layer clays. Much less damage wascaused by the PHPA polymer/KCl-based fluids, which apparently stabilized the fibrous illite-smectite.
Batching Setting of Deviated 30-in. Conductors
Authors: Oag A. W.
Published: December 2007

Britoil plc operates the Clyde field in the U.K. Continental Shelf (UKCS) on behalf of its coventurers Shell and Esso. The field was discovered in 1978 and a single production platform was installed in 1986.

During the Clyde project design phase, drilling personnel co-ordinated the requirements of conductor setting with the jacket structure, drilling rig and wellhead systems design. It was necessary to set the conductors at a depth of 550 ft below the mudline to obtain sufficient formation strength to allow mud returns to surface and safe diversion of potential shallow gas. During the planning phase conductor running and cementing procedures were broken down into a detailed operations sequence. The necessary procedures and specialist tools required for the job were developed to minimise conductor handling times.

Drilling techniques involved using a top drive unit in combination with a turbine to directionally drill a 17.1/2″ pilot hole to 550 ft below seabed up to inclinations of 4 to 5 degrees. This resulted in the earliest possible separation of wells being achieved. The pilot hole was subsequently opened to 36″ in a single underreaming operation.

The cementing procedure for open-ended conductor was developed especially for Clyde from a technique used on another operated field. The slurry was pumped through a stinger and electric logs were adapted to monitor the tops of cement inside the conductor and in the open hole annulus while cementing. Minimal time was spent waiting on cement to set before it was possible to leave the conductor free standing and move on to the next one.

Britoil has so far set 16 conductors in this way. And through detailed pre-planning and implementing changes when required, has achieved conductor installation to 550 ft penetration in under two days.
Mechanistic Approach in Designing BHA's and Forecasting Wellbore Position
Authors: Rafie S.
Published: December 2007

BHA bending analysis and drilling ahead prediction are important topics because they can improve drilling efficiency and help prevent unplanned borehole deviation. Without them, there is extra risk of undesirable deviation which can cause severe drilling problems and greatly increase the cost of drilling. This paper presents the analytical basis and field applications of an integrated computer method in directional drilling. The method includes two-dimensional BHA bending analysis for designing BHAs and predicting their deviation tendencies, and a heuristic formation-bit interaction model for forecasting the future wellbore position while drilling. Using this computer method, parametric studies are performed on several single and multi-stabilizer bottom hole assemblies to demonstrate the effects of stabilizer placement and wear, WOB (weight on bit), hole angle, and borehole current curvature on the deviation tendency of these assemblies. Predicted wellbore positions from the drilling ahead model are compared with actual field data for two directional wells.
The Characterization of a Drilling Fluid Additive
Authors: England A. A. , Davis N.
Published: December 2007

The guidelines for selection of a drilling fluid additive have changed during the past few years. No longer is performance the only criterion to characterize an additive. Demands on the drilling mud specialist to select the correct additive comes not only from drilling personnel, but also from explorationists, production personnel, purchasing agents, and governmental agencies.

Recent advances in analytical instrumentation and techniques utilizing gas chromatography and pyrolysis have provided geological personnel insight into the masking effects of mud additives in evaluation of exploration prospects. Government regulations on both offshore and land operations have restricted or precluded certain additives which normally would be used in this environment. Concerns about the damaging effects of mud additives in hydrocarbon production zones have increased in our present efforts to maximize production. The mud specialist faces a dilemma in selecting an additive which can satisfy and/or minimize these concerns.

This paper lists seven parameters which one company uses to characterize and rank drilling fluid additives. These include cost, performance, quality, environmental effects, production and exploration evaluation compatibility, drilling utilization, and logistics. In addition, the paper discusses the methods this company uses in evaluating additives under these established parameters and how the information is disseminated to operating units for utilization.
Appropriate Design of Drillpipe Internal Upset Geometry Focusing on Fatigue Property
Authors: Tsukano Y. , Nishi S. , Miyoshi H. , Sogo Y.
Published: December 2007

Drill pipe fatigue failure initiated at the transition area of internal upset is one of the most serious problems. A method to prevent this type of failure is described focusing on an improvement in the internal upset design. Firstly, a design was conceived in which the stress in the transition area of internal upset never exceeds that at the external surface of pipe body under bending moment. Secondly, finite element analysis was employed to obtain the appropriate internal upset geometry based on the design concept. Finally, the validity of the criterion given by the finite element analysis was evaluated by full-size fatigue tests and excellent agreement was obtained.
A Field Comparison of the Directional Accuracy of MWD in Comparison With Six Other Survey Tools
Authors: Gabris P. M. , Hansen R. R. , Bartrina J.
Published: December 2007

A recent high angle well in the Mediterranean Sea offered a unique opportunity to compare survey tools. Seven different survey tools from six different companies were used over the same hole section, enabling their performance to be compared under the same conditions. Only the MWD tool gave consistently accurate survey data throughout the entire well.
Development of the Gullfaks Field
Authors: Grinrod M. , Justad T. , Tomren P. H.
Published: December 2007

The development of the Gullfaks field includes three giant gravity based platforms and subsea wells.

This paper describes the field, the drilling program and the drilling equipment installed on the platforms.

Shallow gas and abnormal pore pressure are among the challenges the operator faces. The block was awarded to a group comprising Statoil, the operator (85%), Norsk Hydro (9%) and Saga Petroleum (6%) in 1978. Exploration drilling commenced the same year.
The Application of Robotics to the Drilling Process
Authors: Boyadjieff G. I.
Published: December 2007

Robotics, a recently popularized phrase, has captured the interest of the general public as well as the drilling industry. This paper reviews the history of robotic applications in drilling and their outcome for the purpose of determining future trends. An analysis of the obstacles and limitations common to all industries is used to adjust the trend projection, and a survey of current efforts and programs is presented to complete the presentation.

Applications analyzed include the automatic drilling rig, various pipe-racking systems, and recent offerings in pipe-handling machines.
Innovative Approaches to Drilling High-Angle Wells in Bass Strait
Authors: Shaw M. N. , Sutherland W. G.
Published: December 2007

Esso/BHP has used innovative approaches to drilling high angle wells up to 72° average angle on its Snapper platform in Bass Strait. Drillstring designs, bit selection, hole conditioning, fishing, cementing and completion techniques have been reevaluated for innovation and cost-effectiveness. These techniques were used to make a comprehensive redrill program technically and economically viable.
Use of Borehole Stability Analysis for Successful Drilling of High-Angle Hole
Authors: Fun G. F. , Whitfill D. L. , Schuh P. R.
Published: December 2007

The removal of rock during the drilling operation disturbs the natural rock formation that is being subjected to a state of compressive in situ stresses at depth. The redistribution of the stresses around the hole thus produces stress concentrations at or near the borehole wall. Having no effective control to counter the high stress buildup around the wellbore may lead to a number of hole problems that include stuck pipe, borehole collapse, sloughing shale, and excessive fill. Using the theory of elasticity in rock mechanics, a numerical model has been designed to practically evaluate the stability of hole conditions both before and during drilling operations. This paper addresses the control of mechanical instability due to stressed conditions other than the interaction of mud chemistry on the rock formations. Case analyses are presented for offshore drilling in the Gulf of Mexico. The results have shown that the rock mechanics modeling of borehole stresses can help achieve the successful drilling of high-angle holes using optimum mud weights determined in advance for controlling hole stability.
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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.
Dale/Coteau/Bluell Development and Economics, Burke County, North Dakota
Authors: Ausmus G. H. , Borchert R. N.
Published: December 2007

Mississippian age formations have been an historic exploration objective in the Williston Basin. In the period between 1980 and 1987, over 300 wells were drilled in the study area, most of which tested the Dale, Coteau, or Bluell subintervals of the Mission Canyon formation.

This review of development in central Burke and northwest Ward counties was undertaken to evaluate the past and future economics of this exploration objective. Specifically, the reserves discovered by 1980-1987 Mission Canyon development were quantified, and the reserves required to reach minimum historic and present investment hurdles were determined. Comparison of past development to the historic investment hurdles showed that one-third of the 134 completed wells were profitable. Correlation of profitable well locations to regional geologic structure revealed that the profitable wells generally produced from traps with the greater degree of transverse structural closure. Ancillary topics relating to study area geology and shallower Charles formation reserves were also addressed.
On-Site Computer Monitoring of Foamed Stimulation Fluids
Authors: Baumgartner S. A. , Mack D. J.
Published: December 2007

Computerized monitoring of hydraulic fracturing treatments has been an accepted practice for several years. Not only can a continuous record of the treatment parameters be made, but the real-time bottomhole treating pressure can be determined without the use of a reference string or bottomhole pressure tool. However, to calculate the bottomhole treating pressure, the friction pressure of the fluid or slurry must be determined. For conventional, incompressible oil and water-based fluids friction pressure is a straightforward calculation since rate and proppant concentration are the main considerations. The friction pressure for foam fracturing fluids requires a more complex solution.

A computer van was used to monitor carbon dioxide and nitrogen foam treatments incorporating a reference string or bottomhole pressure tool. The following parameters involved in the calculation of bottomhole treating pressure were examined in this study: injection rate, addition of proppant, effect of proppant on slurry friction pressure and foam hydrostatic head pressure. This paper presents a technique which allows the bottomhole treating pressure to be calculated without the use of a reference string or bottomhole pressure tool. The calculation of bottomhole treating pressure for a foam treatment incorporates a technique to correct the hydrostatic head pressure of carbon dioxide and nitrogen foams. In addition, the different effects of proppant addition on friction pressure between nitrogen and carbon dioxide generated foams are discussed.
Practical Application of a Reservoir Model to EOR: Lone Cedar (Minnelusa) Unit, Campbell County, Wyoming
Authors: King W. A.
Published: December 2007

The Lone Cedar Field waterflood feasibility study had the advantage of having a complete set of logs, cores, core tests, fluid tests, reservoir pressure tests and daily production history on all producing wells. In addition the field was small enough to simulate on a personal computer.

The data was organized, calculated, summarized, compared, plotted, and prepared for the simulator using many computer generated spreadsheets. A three dimensional-three phase black oil simulator and a two dimensional polymer simulator were used to design the polymer augmented waterflood.
Accurate Design of Fracturing Treatment Requires Conductivity Measurements at Simulated Reservoir Conditions
Authors: McDaniel B. W. , Parker M. A.
Published: December 2007

Recent fracture conductivity testing in the laboratory has achieved a new degree of realistic simulation of reservoir fracture conditions. Many investigators are now attempting to develop more accurate testing procedures. At least two laboratories have published data where conductivity tests have simultaneously included the effects of gel filter cakes, formation core effects, and extended test times at representative reservoir stress and temperatures. In this paper, work published in 1986 and 1987 is reviewed, and additional conductivity data with gel filter cakes are presented. Data showing the result of varying the proppant concentration inside the fracture from 0.75 up to 2.8 lb/ft2 are presented for the first time, showing that the effect of proppant concentration can not be neglected.

The economic success of hydraulic fracturing treatments depend on obtaining sufficient fracture conductivity within the proppant bed. This is illustrated by using a fracture design simulator to model the resultant propped fracture geometry and proppant distribution. By incorporating laboratory measured conductivity values (where gel filter cakes are present) these simulations show the importance of having realistic conductivity data when trying to optimize the treatment design.
Successful High Angle Completions, Cementing, and Drilling’s Impact
Authors: Fontenot J. E.
Published: December 2007

Successful well completions are the key to exploiting the potential benefits of high angle/horizontal drilling. Successful primary cementing is vital to completion success. Cementing success is often jeopardized by the wellbore created during the drilling process. This paper unfolds this dilemma and takes a look at what must be done to overcome it.
Application of Laplace Transformation to Elliptical Flow in Naturally Fractured Reservoirs: Part II-Field Applications
Authors: Okoye C. U. , Oyefodun A. , Matese J. J. , Hayatdavoudi A. , Ghalambor A.
Published: December 2007

In part II of this study, we present the application of the unsteady state solutions to fluid flow in naturally and or vertically fractured reservoirs whose internal boundaries are assumed to be ellipticaliy shaped. Type curves generated using solutions to unsteady-state elliptical flow equations are used to analyze several published field pressure data for parameters such as permeability, skin factor, wellbore storage and fracture length.

The field data analysis results show close agreement with results obtained using other reservoir flow geometries such as radial or linear.