bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effective Acid Diversion and Water Control in Carbonate Reservoirs Using an Associative Polymer Treatment: Case Histories From Saudi Arabia
Authors: Al-Taq Ali A. , Nasr-El-Din Hisham A. , Lajami Ridha A. , Sirra Leopoldo 
Published: December 2007

AbstractAcid diversion and water control are usually addressed as two separate issues in the oil industry. An associative polymer can be used to simultaneously address these two issues in a single treatment. Associative polymer treatments were successfully applied during matrix acid stimulations in onshore and offshore oil carbonate reservoirs in Saudi Arabia. The oil producers were completed as perforated and open hole wells. The associative polymer was applied in combination with acid treatments mainly to: 1) mitigate the preferential stimulation of water saturated zones located near oil producer layers, 2) improve acid diversion in heterogeneous carbonate reservoirs, and 3) restore the productivity of the damaged wells.Extensive experimental studies were carried out to investigate potential use of an associative polymer to control water mobility and act as an acid diverter. Coreflood experiments (parallel cores) conducted on reservoir cores at downhole conditions showed that the polymer treatment has no significant effect on the relative permeability to oil. However, the relative permeability to water was significantly reduced. In addition, the associative polymer was very effective in diverting acid into oil-saturated cores.This paper presents the results obtained from several wells where an associative polymer was applied successfully during matrix acid treatments of damaged wells. All the treatments included stages of associative polymer solutions and 20 wt% HCl with additives. Post stimulation treatments production data, build-up, downhole gauges and production logging confirmed that the associative polymer was very effective in diverting the acid into oil saturated zonesand resulted in a significant reduction in water production.
Tomographic Reconstruction Techniques for Reservoir Monitoring
Authors: Kretzschmar J. L. , Kibbe K. L. , Witterholt E. J. 
Published: December 2007

ABSTRACT
Tomographic reconstruction techniques, using radio frequency electromagnetic wave data, have been applied to the monitoring of fluid distributions at three different enhanced recovery pilot sites.
The attenuation of waves propagating between observation wells was measured at multiple frequencies in the range from 1 to 30 MHz. On two sites more than one pair of wells were available, permitting varied views of the reservoir.
Different versions of published tomographic reconstruction algorithms were applied to both real and synthetic data. The algorithms used include those with both single ray path and lumped system convergence principals.
Results show that tomographic reconstruction requirements vary with reservoir and "system" operations, i.e., well spacing, geometry, frequency, rock/fluid parameters, dynamic range, density of data, and computational techniques. Reconstructions of the same reservoir zone at several frequencies appears to be especially diagnostic.
For those unfamiliar with the terminology, "tomograph" is a "picture of a slice;" in this case a vertical slice bounded by the two boreholes. The reconstruction technology is analogous to that currently used in diagnostic medicine to create "pictures" of the interior of the human body using x-rays or ultrasound.
In "geo-tomography" the probing energy is electromagnetic or elastic (seismic) waves.
Acoustical Anisotropy of Cotton Valley Shale
Authors: Tosaya Carol A. 
Published: December 2007

ABSTRACT
The dynamic elastic stiffnesses of transversely isotropic Cotton Valley silty shale were computed from ultrasonic-frequency compressional-and shear-wave velocity measurements. The measurements were made in three oriented right cylinders of fully water-saturated shale. Confining pressure was varied to 1100 bars for a constant pore pressure of 50 bars.
All velocities and corresponding elastic stiffnesses increased with differential pressure in a manner that suggested continuous closure of pores and cracks and increasing alignment of platy clay particles with pressure. In addition, elastic anisotropy was found to increase with stress level, evidently approaching the intrinsic anisotropy of the zero-porosity, statistically weighted, aggregated volume fraction of the dominant clay mineral.
Expressions for the elastic stiffnesses were derived for the boundary-value problem of plane strain, the conditions for which are approximated by wave-propagation measurements using an ultrasonic-frequency, pulse-transmission technique.
The Filling of Oil Shale Mines With Spent Shale Ash; Ash Characteristics and Grout Development
Authors: Watson George H. , Ziemba Eugene A. , Bissery Paul , Namy Dominique , Griff Robert L. , Nicholson David E. 
Published: December 2007

ABSTRACT
Rio Blanco Oil Shale Company (RBOSC) has considered the modified in-situ (MIS) process as one of the alternatives for extracting oil from oil shale at Tract C-a. One of the problems to be solved for this approach is the environmental consequence of underground retort abandonment. This includes possible contamination of groundwater as the natural groundwater regime is re-established, aerial subsidence, aquifer mixing and underground disposal of surface-retorted materials. This paper outlines the four-phase program under contract to the Department of the Interior, Bureau of Mines, which is being used to address the problem and details the laboratory and pilot scale testing.
Effect of the Sodium and Ammonium Content and the pH of Carbonate Uranium Leachates on the Permeability of a Core From the Catahoula Formation in South Texas
Authors: Otto J. B. 
Published: December 2007

ABSTRACT
This paper reports a laboratory study of the effect of the Na+ and NH4+ content and the pH of carbonate uranium leachates on formation permeability. The purpose of the work was to define conditions such that the leachate would not appreciably decrease formation permeability or cause significant formation damage. The core used in this study was obtained from a uranium zone in the Catahoula formation. It contained about 3% of the expandable clay, smectite, and had a permeability of 2000 md.
Increasing the Na+ content of a leachate 3-fold by a 10-fold increase of the CO3= content from 600 to 6000 ppm by NaHCO3 addition at pH 8 caused a 10% decrease in permeability presumably because more of the smectite had been converted to the swelling Na+ form by ion exchange. Displacement of the 6000 ppm CO3= as NaHCO3 leachate by a 6000 ppm CO3= as (NH4CO)3 leachate at pH 9.4 caused a reversal of the loss in permeability and even a slight increase over the initial permeability presumably because the smectite had been converted to the non-swelling NH4+ form. The effect on formation permeability of Na+ and NH4+ leachates at pH 8 to 9.4, therefore, appears to be reversible. Reversibility of permeability suggests that these leachates do not cause formation damage.
In contrast, a 0.3M NaCl-0.2M NaOH, pH 13, restoration solution used for NH3 removal from formations caused an immediate, irreversible 40% decrease in permeability presumably because the highly caustic solution caused formation damage by chemical reaction with the formation.
Aspects of Slurry and Particle Settling and Placement for Viscous Gravel Packing (AQUAPAC)
Authors: Torrest Robert S. 
Published: December 2007

ABSTRACT
During gravel packing with viscous agueous polymer slurries as in Shell's AQUAPAC, the concentrated suspensions may move at higher velocity than the surrounding fluid. We show here that these concentrated suspensions tend to disperse rapidly in the well-bore. The term "roping" is not a suitable description of the phenomena. Measurements and estimates of single particle settling velocities are presented. The use of such measurements to determine polymer viscosity for field applications is suggested. Finally, since gravel packing calls for fluid placement to the formation, new results for particle placement through perforations show that even dilute 0.25%w polymer solutions give up to 100% placement efficiency for some conditions of interest.
The Flow of Viscous Polymer Solutions for Gravel Packing Through Porous Media
Authors: Torrest Robert S. 
Published: December 2007

ABSTRACT
Gravel packing with viscous aqueous polymer solutions, as in Shell's Aquapac, often calls for fluid placement to the formation. To estimate placement pressures experiments have examined the flow of suitable polymer solutions through porous media ranging from coarse spherical beads to gravel pack gravel and simulated formation sand. The solutions are shown to follow power-law behavior, and pressure drops within the porous media can be described in terms of a simple power-law model. However, the solutions tend to form a gel at the inlet surface of the pack. The surface impairment may dominate the overall pressure drop particularly in the case of formation-like permeabilities. The surface buildup and potentially rapid viscosity breaking may effectively prevent meaningful predictions of pressure response. The results suggest that placement with these solutions may sometimes be very different than intended. Unanticipated high downhole viscosities may suggest interpretations involving "premature sandout." However, breakers can substantially reduce downhole viscosity during placement. Since the nature of gravel pack buildup is strongly dependent on solution viscosity, the detailed behavior may have an important influence on gravel pack effectiveness and productivity.
Multiphase Flow in Porous Media: I. Macroscopic Observations and Modeling
Authors: Salter Stephen J. , Mohanty Kishore K. 
Published: December 2007

ABSTRACT
Tracer displacements were run during steady-state, two-phase flow, where tracers were added to both the wetting and nonwetting phases. Such experiments were conducted in the primary drainage, imbibition, and secondary drainage cycles over a wide range of fractional flows. The effluent tracer profiles from these experiments were fit with a four-parameter, capacitance-dispersion model, which divides each phase into three fractions: flowing, dendritic, and isolated. Mixing in the flowing fraction is described by a dispersion coefficient, and communication between the flowing and dendritic fraction is represented by a single mass transfer coefficient. This model is shown to adequately fit tracer effluent data over a wide range of conditions.
In some areas the model is nonunique--thus, more than one solution fits the experimental data equally well. Additional experiments were conducted to differentiate mechanisms in these regions. The effects of core wettability were investigated and shown to be important. The results of all of these experiments were used to formulate a mechanistic picture of steady, two-phase flow in strongly wetted porous media.
Evaluating the Impact of Waterfrac Technologies on Gas Recovery Efficiency: Case Studies Using Elliptical Flow Production Data Analysis
Authors: Ilk D. , Rushing J. A. , Sullivan R. B. , Blasingame T. A. 
Published: December 2007

AbstractThis paper presents results from an evaluation of water-based hydraulic fracture stimulation treatments (or "waterfracs") performed in the Bossier tight gas sand play in the East Texas Basin. The primary objectives of our study were to not only assess stimulation effectiveness, but also to compare recovery efficiencies of various waterfrac technologies. Our primary evaluation tool is a set of new decline type curves developed specifically for the analysis of production data acquired from the elliptical flow period commonly observed in hydraulically- fractured wells completed in tight gas sands [Amini et al (2007)].In this study we evaluated 12 gas wells from three Bossier tight gas fields located in Freestone County, Texas. Stimulation treatments for the wells in this study include water-based hydraulic fracture stimulation treatments with little or no sand, cases with large sand concentrations, as well as "hybrid waterfracs." "Hybrid waterfracs" are defined as fracture stimulation treatments where water is pumped initially to create the fracture geometry (i.e., width and length), followed by sandladen gels to transport and place sand in the fracture (presently low concentration gels are used as opposed to large concentration gels used in the 1980s).Results from our study confirm that "hybrid waterfracs" yield longer, more conductive hydraulic fractures and are more effective at recovering gas-in-place for a given well spacing. Although less expensive to implement, small "waterfracs" (with little or no sand/proppant) are less efficient at gas recovery — which suggests more wells may be required to maximize gas recovery when "waterfracs" are employed.
Succeeding With Multilateral Wells in Complex Channel Sands
Authors: Song Liu , Jianping Li , Dingyu Lv , Kok Jeffrey , Han Shim Yen 
Published: December 2007

Abstract
The lower Minghuazhen is a shallow-water, delta-plain, sedimentary-deposit reservoir sand in Bohai Bay, China. It has relatively heavy oil in place that is high in viscosity. With the understanding that horizontal or multilateral profiled wells are the most favorable design to economically increase individual well production and reservoir drainage, an ambitious program was embarked upon to drill 11 of these wells in the first phase of a drilling campaign.
Although the sand is well defined in offset wells and the structure had been interpreted to correlate between them, Phase I of drilling yielded disappointing results; and only 5 of the planned 11 wells were completed as planned.
To guide the second phase of the development program in which multilaterals were still in favor, a different approach was necessary. The available 3D seismic data was reprocessed using frequency spectrum imaging to better understand target definitions. In addition, Phase I was analyzed in terms of drilling, operational procedures, processes, tools selections and well designs to identify root causes and to learn from them. These studies were then applied to overcome the cannel structural complexities, thus implementing the course of action for seven multilateral wells on Phase II.
Shear Wave Travel Time Determination Using an Unconventional Approach
Authors: Frost Elton , Fertl Walter H. 
Published: December 2007

ABSTRACT
In the past, numerous techniques have been used in attempting the downhole determination of formation shear travel time. These include visual inspection of full wave train recordings (e.g., variable density, signature, microseismogram), monitoring the amplitude characteristics of the acoustic wave train in selected gate(s), digital analysis of the acoustic wave train in selected gate(s), experimentally defining a relationship between compressional and shear wave transmit times, digital analysis of the acoustic wave train at various transmitter-receiver (T-R) spacings, etc. These techniques have had only limited success, particularly in shaly, unconsolidated, undercompacted and/or gas bearing formations.
A new analytical model has been developed and tested which overcomes some of these constraints. By utilizing the standard compressional travel time in conjunction with supplementary non-acoustic logging data, the shear travel time can be estimated with reasonable accuracy in clastic (sand/shale) sequences.
Physical Simulation of In-situ Combustion of Sensitive Heavy Oil Reservoir
Authors: Wenlong Guan , Shuhong Wu , Shihu Wang , Junhe Cao , Yaping Chen 
Published: December 2007

Abstract
Block Z, one of reservoir of Shengli Oil Field, is a sensitive heavy oil reservoir with high content of kaolinite and illite. From 1992 to 2002, more than ten-year's water drive and steam huff and puff had seen poor production performance. In 2003, in-situ combustion pilot test with 1 injector and 11 producers was carried out to improve development performance and, simultaneously physical simulation is designed to evaluate the pilot test. The paper will detail the physical experiments of in-situ combustion, its experiment apparatus, its process, and its results. Also, it will briefly introduce production history and performance of pilot test.
Several experiments have been carried out and the results show that air injection rate is the key factor to influence the fire flooding, the higher injecting rate and the higher the advancing speed of combustion front. For complete combustion with plentiful air supply, no coke comes into being and the formation remains undamaged without permeability decrease. For the sensitive reservoir, the component of rock has changed after burning, and the reservoir has turned into low sensitive to water and steam. In front of burning zone, high oil saturation bank is formed, in which pressure decreases greatly during fire flooding. When the bank is away from the producer, the producer shows low productivity. Once it goes near to the producer, productivity increases step by step.
Experiment results have been successfully used to evaluate the pilot test and to improve the performance. Up to now, the pilot test has been lasting for more than 3 years and more than 26.7×103t oil has been produced.
Case History—Installation of High Volume Pumping Equipment in Talco Field, Texas
Authors: Rose James D. 
Published: December 2007

ABSTRACT
The paper presents a case history study of Exxon's high volume artificial lift program at Talco Field in Franklin and Titus Counties, Texas. The field, discovered in 1936, produces heavy crude oil from the Paluxy Sandstone at an approximate depth of 4200 feet. All wells required artificial lift installation soon after the field was discovered due to rapid salt water breakthrough. Primary recovery efficiency is expected to be only about 35 percent of the original oil in place, attributed to reservoir heterogeneity and the adverse water-oil mobility ratio. Through installation of high volume artificial lift equipment, current data indicate that significant additional recovery benefits may be realized.
The paper details the practical experience Exxon has gained since the first high volume electric submersible pump was installed at Talco in 1974. Included are screening parameters used to optimize the selection of particular high volume artificial lift equipment. Also included are representative production flowstreams to quantify the additional recovery expected of typical electric submersible pump and large capacity beam pumping unit installations. An analysis of the incremental expenses and costs associated with electric submersible pumps and large capacity beam pumping units is presented. Also discussed are case production histories and operational problems encountered with actual installations.
Optimisation of Solids Control Opens Up Opportunities for Drilling of Depleted Reservoirs
Authors: Omland T. H. , Dahl B. , Saasen A. , Taugbøl K. , Amundsen P. A. 
Published: December 2007

Abstract
Experience has shown that adding suitable particles to the drilling fluid can significantly improve the formation strength. This is especially beneficial when drilling wells with a narrow operational window as is typically the case when drilling depleted reservoirs. Successful operations have employed several types of particles, including graphite and calcium carbonate. For this kind of approach to work, it is important to establish an optimal particle composition in the drilling fluid. In a recent paper, SPE 107574, the possibility for continuous monitoring of the particle size distribution (PSD) and particle content in the drilling fluid, was demonstrated. This present work shows how these findings have allowed deploying a unique technique for running of solids control equipment in a North Sea offshore field, providing optimal particle concentration and size distribution when drilling a significantly depleted reservoir. We describe in detail an HTHP offshore operation where coarse shaker screens were used to allow relatively large particles to re-enter the well during circulation. These particles act just like particles deliberately added to the drilling fluid in order to enhance formation strength. The monitoring equipment allowed for close control of the PSD of the drilling fluid flowing into and out of the well during drilling. The particle size distribution is compared to that obtained with conventional additives previously used to achieve formation strength enhancement.
Silurian-Niagaran Reef Belt Around the Michigan Basin—A Synergistic Review
Authors: Aminian Khashayar , Tek M. Rasin , Wilson James L. 
Published: December 2007

ABSTRACT
The Silurian-Niagaran pinnacle reefs occur on a belt which encircles the entire Michigan Basin including areas presently covered by the Great Lakes. The annual production from these reefs in Michigan has reached 30 million barrels of oil and 150 billion cubic feet of natural gas.
Two different structural settings existed in the Michigan Basin during the Silurian Period, which resulted in formation of the pinnacle reefs with somewhat different characteristics in different parts of the basin. The pinnacles of the northern trend occur at depths of 4000-7000 feet, are up to 700 feet thick, and average about 100 acres in area. The southern pinnacles occur at depths of 2000–3000 f shorter, about 300 feet thick, and attain larger areas. The pinnacle reefs underwent several diagenetic changes, which resulted in concentration of the majority of the hydrocarbon reserves of the northern trend in pinnacles which occur on a band 3-4 miles wide inside the middle of the trend. There exists a regional partitioning of oil and gas in the northern pinnacle reefs, which can best be explained by Gussow Theory of migration and differential entrapment. Such a reserve concentration or hydrocarbon differentiation has not been observed in the southern trend.
A probabilistic model for exploration in a play was found applicable in mature areas of the northern trend and the results were extended to other parts. The results suggest that the effectiveness of exploration, based on seismic surveys, is 8 to 10 times better than random drilling. The reserves of the reef belt are in excess of 7 billion barrels of oil and 15 trillion cubic feet of natural gas in place.
Simulation of the Wellbore Hydraulics While Drilling, Including the Effects of Fluid Influxes and Losses and Pipe Washouts
Authors: Millheim Keith K. , Tulga Said Sahin 
Published: December 2007

ABSTRACT
This paper presents a method to simulate the circulating system while drilling a well. For any given pump rate the pressure losses through the surface system, down the drill pipe, through the bit, and up the annulus can be determined. The algorithm also has the capability of simulating a washout in the drill string, losing fluid to the formation, having fluid produced into the annulus, and fracturing the formation(s).
The algorithm is general enough to calculate pressure losses for turbulent and laminar flow, simultaneously. This covers the situation where multiple flow regimes exist in the same circulation loop.
Formulation of the algorithm is presented, showing how a network type of solution is used to calculate the pressures and flows. The iterative solution converges rapidly and can be used for real time and faster than real time simulation.
Detailed surface pressure data was obtained from two wells in Texas. The circulation simulation program was used to calculate pressure losses at various depths in each well for a variety of circulation rates. Results presented in this paper show close agreement with the field data.
To show the versatility of the simulation algorithm a series of idealized circulation system simulations are presented. These include various downhole circulation situations such as lost circulation, circulation without returns, and fluid production response as a function of permeability and pressure, and circulating with a hole in the drill string.