bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experiences on Heavy and Extra-Heavy Crude Rod Pumping Automation Applications using Thermal and Dilution Techniques
Authors: Fernandes José , Lastra Alí 
Published: December 2007

Abstract
In heavy and extra-heavy oil production, additionally to the rod-pumping artificial lift method, we must consider using fluid's physical property modification in order to make it easier to produce and distribute. Some methods widely used are steam and dilute injection in order to modify oil viscosity and API, respectively.
Optimizing Alternate Steam processes implies monitoring variations in Steam injections cycles and observe the well production decrement as cycles are completed. One way to optimize production in each cycle is controlling rod-pumping speed, not only to obtain the more production we can, but also to preserve well energy in order to span cycle life. Also, with the information collected, it is possible to make the well by itself indicates when to start a new steam cycle and observe well's declination.
Dilute optimization is a continuous process that considers injection in field and production line. Experiences were collected based on saving dilute injected and obtaining oil production keeping a high cost/benefit relationship.
Applying Curvature and Fracture Analysis to the Placement of Horizontal Wells: Example from the Mabee (San Andres) Reservoir, Texas
Authors: Yuan Qiu , Holtz M. H. , Yang Anping 
Published: December 2007

Abstract
San Andres carbonate reservoirs have long been known to have a high degree of reservoir heterogeneity and poor recovery efficiencies. Fractures are one of several causes of this heterogeneity. The heterogeneity causes unpredictability in water and CO2 flooding. However, the correct placement of horizontal wells can take advantage of this problem.
An integrated reservoir characterization study of the Mabee field incorporating oriented core, Formation Microscanner (FMS) wireline logs, seismic time slices, production character, curvature analysis, and interference testing was used to predict fracture orientation and areas of highest fracture density. These fracture characteristics were then applied to determine horizontal well location and orientation. Fracture orientation was evaluated through the analysis of oriented core, FMS logs, and interference testing, indicating a fracture orientation of N70W. Analysis of the induced fractures in the oriented core indicates that the direction of maximum horizontal compressive stress is N45E. High fracture density was delineated by curvature analysis, relative seismic amplitude, and areas of higher production. Areas with high curvature corre- spond to areas of high relative seismic amplitude and higher production. The data integration indicates that four areas have high fracture density. The synthesis of fracture orientation and density, along with the production character, indicates the optimal location and orientation of horizontal wells.
Water Injectivity Decline Caused by Sand Mobilization: Simulation and Prediction
Authors: Yi X. 
Published: December 2007

Abstract
Water injectivity decline is a very common phenomenon in waterflooding fields. Most of the previous analyses were focusing on water injectivity decline due to the migration of suspended particles in injection water or the injection water/reservoir fluid incompatibility. However, in some unconsolidated formations, another possible mechanism for water injectivity decline is sand mobilization, which means sand particulates separate from rock matrix and move into deep formation. This kind of injectivity decline is controlled by the operation condition of water injection such as injection pressure and injection rate. In this paper, a mathematical model is proposed to simulate the process of sand mobilization and the resultant water injectivity decline.
The mathematical model is derived based on material balance for water, sand particulate, and rock matrix. Also included in this model are particulate generation and deposition constitutive laws, and permeability-porosity correlation. Finite difference scheme is introduced to discretize the partial differential equations and the finite difference equations are solved implicitly through iteration. Sensitivity analysis is performed to study the effects of various factors on water injectivity decline and strategies for managing efficient water injection are proposed through the analysis.
Reservoir Permeability Determination Using After-Closure Period Analysis of Calibration Tests
Authors: Benelkadi Said , Tiab Djebbar 
Published: December 2007

Abstract
Hydraulic fracturing has generally been limited to relatively low-permeability reservoirs. In recent years, the use of hydraulic fracturing has expanded significantly to high permeability reservoirs. The objectives of fracturing low permeability reservoirs and high permeability reservoirs are different and defined by reservoir parameters.
The estimation of reservoir permeability, a variable of great importance in hydraulic fracturing design is frequently unknown because candidate wells either do not flow or a pretreatment pressure transient test is required. Consequently, Nolte has introduced a new method for adding after-closure fracturing analysis to the pretreatment calibration testing sequence that defines fracture geometry and fluid loss characteristics. The exhibition of the radial flow is ensured by conducting a specialized calibration test called mini-fall test. The derivations by Nolte, based on the theory of impulse test and principle of superposition, allow the identification of radial flow and thus the determination of reservoir transmissibility and reservoir pressure.
This study presents a review of the after-closure radial flow analysis. A modified method is proposed to complete the Nolte’s method for the determination of the reservoir transmissibility and reservoir pressure based on the pressure derivative.
The application of the modified method is demonstrated on actual field data from calibration tests performed on several oil and gas wells. The reservoir parameters determined with this method are verified by comparison with results obtained from buildup tests.
Horizontal Injectors Rejuvenate Mature Miscible Flood - South Swan Hills Field
Authors: Edwards K. A. , Anderson B. , Reavie B. 
Published: December 2007

Abstract
The South Swan Hills Unit, located in north-western Alberta, is a carbonate reef with an original-oil-in-place (OOIP) of approximately 850 MM bbl. Waterflooding was begun in the field during the 1960s, and a staged hydrocarbon miscible flood was begun during the 1970s. Chase gas injection was terminated in the mid-1990s. In 1994, however, miscible flooding was reinitiated in the reef margin area of the field using horizontal injectors and reduced well spacing. The reef margin is an area of thick, stacked pay that experienced high gravity override during the original miscible flood. Four patterns have been developed to date. The two earliest patterns have now completed solvent injection and are on chase waterflood. They have both recovered between 800 M bbl and 900 M bbl of incremental oil per pattern (more than 10% of pattern OOIP) from areas which were part of the original miscible flood.
This paper will detail the past history of the pool under miscible flood, the redevelopment of the reef margin area using horizontal miscible injectors, and the performance of the four patterns implemented to date. The factors that have made this redevelopment successful, and their impact on field production, will also be discussed. Finally, plans for future development of this mature field will also be discussed.
Use of Sewage Effluent as a Water Flood Medium Mattoon Pool, Illinois
Authors: Simmons J.D. 
Published: December 2007

Abstract
The Mattoon water flood, located in south Central Illinois, encompasses 450 acres and includes 28 injection and 32 producing wells. A pilot flood utilizing Pennsylvanian age brine proved the feasibility of flooding the Mississippian age formations at Mattoon pool. However, since usable subsurface brines were limited in availability, an expansion of the project could be achieved only after another source of compatible water was found. One such source was the effluent from the municipal sewage disposal system of the city of Mattoon. This effluent carries considerable suspended matter in addition to aerobic and anaerobic bacteria. Following a series of tests, a satisfactory treating method was developed, consisting of chlorination, settling, and filtration. A contract was negotiated with the city of Mattoon to purchase the sewage effluent and injection began in May, 1954.
During the summer of 1955, additional tests revealed that produced water from the oil wells could be mixed with the effluent without additional treating and, during September, 1955, the produced water was introduced into the injection system. Currently, some two and one-half million bbl of sewage effluent have been injected with no permanent plugging of input wells being evidenced. Phosphates, principally of iron, resulting from the presence of detergent soaps in the sewage effluent continue to form after filtration but are readily removed by periodic acid treatments of the wellbores. Although the cost per barrel of water injected is greater than for similar floods using subsurface brines, and considerable time is required to control quality, sewage effluent has proven to be a satisfactory injection water.

Introduction
The Mattoon pool, located along the west side of the city of Mattoon, Illinois, was discovered in June, 1940. Development of the pool proceeded at a moderate pace and was not essentially completed until 1948. Final development included approximately 420 producers and 90 dry holes drilled on 10-acre spacing. The principal producing horizons are the Cypress and Rosiclare sands of the Mississippian Chester series.
During May, 1952, a 70-acre pilot water flood was initiated to evaluate the feasibility of flooding the Cypress and Rosiclare sands. Product ion increases were realized in November, 1952, and by late 1953, results of the pilot indicated that large-scale flooding would be economically attractive. Water requirements for the proposed expansion of the project were in excess of that available from the Pennsylvanian brine used in the pilot. The only other subsurface water source was the Devonian limestone, found at a depth of approximately 3,000 ft. However, since the Devonian brine was sour, its use would be accompanied by relatively high lifting and treating costs, and its availability in sufficient quantities to meet ultimate requirements was uncertain.
Applying a Time-Dependent Darcy Equation for Decline Analysis for Wells of Varying Reservoir Type
Authors: Hsieh Frank S. , Vega Cecilia , Vega Lucy 
Published: December 2007

Abstract
Decline analysis has been widely applied for predicting hydrocarbon reserves. The approach developed by Arps in 1944 not only is still being used but has also served as the basis for which others developed different approaches. However, with modern day computing facilities the analysis can be conducted beyond the process of identifying lines and curves on semi-log/log-log paper as proposed by Arps or matching the history to the type curves as proposed by other authors. A time-dependent Darcy equation allows for analyzing rate-time decline taking into account the reservoir properties that are unique to the well yet vary with pressure/time. Therefore, it can be used to adequately match the slope of the decline curve that is also changing with pressure/time for the same reasons. The time-dependent Darcy equation also allows for generalizing the decline behavior that is unique to a particular geographical region or reservoir type. In turn, this improves the quality of the analysis, particularly, in a situation where only limited production history is available. Rocky mountain field examples are provided to illustrate the simplicity and the effectiveness of the approach.
Restimulating Tight Gas Sand: Case Study of the Codell Formation
Authors: Sencenbaugh R. N. , Lytle D. M. , Birmingham T. J. , Simmons J. C. , Shaefer M. T. 
Published: December 2007

Abstract
Restimulation of wells completed in the Codell formation, a tight gas sand, has proven to be successful in the Wattenberg Field in Colorado. Beginning in 1997, Codell refracturing evolved into a massive program involving hundreds of wells per year. To date, HS Resources has restimulated over 750 Codell wells, increasing reserves and resulting in a project ROR of 100% with finding costs below $4.23 per barrel oil equivalent. This is a case study of the program conducted by HS Resources.
This paper summarizes the refrac program, and its evolution, since its inception. The candidate selection process is examined, as well as geological and operational considerations when restimulating old wells. The evolution of stimulation treatments and fluids are also investigated. The use of 3D fracture simulations, run in real-time during the refracture treatments, and their results are discussed. Finally, both economic and production results are presented.
Cost Control and Improved Production Performance Revive Drilling Program In 20 Year Old, Giant, Sour Gas Field. A Case Study
Authors: Buzarde C. B. , Guyman G. L. , Seal C. A. , Olds K. T. , Foreman J. M. 
Published: December 2007

Abstract
Carter Creek Field is a giant sour gas field, which was put on production in 1982. After initial development the field was plant constrained for many years. In the early 1990's an infill drilling program was attempted. This program was unsuccessful due to high costs and poor production performance. Late in 1997, a joint Chevron - Halliburton team was put together to make another attempt. Though the program initially met with some adversity, the team persevered and eventually solved the problems that had plagued the past. With cost cuts of 35%+ and initial rates that rival the initial rate of the wells that were completed in 1982 (which had twice the pressure), this program has become a top performer.
Data Mining at a Regulatory Agency to Forecast Waterflood Recovery
Authors: Weiss W. W. , Wo Shaochang , Weiss J. W. , Weber James 
Published: December 2007

Abstract
A new method to predict waterflood recovery is presented. The methodology developed in this paper relies on public information and can be used as a first approximation of waterflood recovery in areas where similar regulatory information is available. This study of 140 pre-1980 hearing records identifies factors that are likely to impact the performance of a waterflood in the Nebraska Panhandle.
The hearing records include a maximum of 30 descriptive entries that could influence the success or failure of a waterflood; however, most records contain only a portion of the possible 30 entries. Success or failure is defined by the ratio of secondary to primary oil recovery (S/P). Primary recovery is defined as cumulative oil produced at the time of the hearing and secondary recovery is defined as the oil produced since the hearing date.
Fuzzy ranking curves were used to prioritize the relevance of 30 parameters on the outcome of the proposed waterflood. Both the range and correlation coefficient of a straight-line fit through the curves were used to rank the inputs to develop neural network correlations. Eight parameters were universally available in 42 of the case hearings, but the number of inputs was reduced to six to avoid overtraining problems. These 42 records serve as the database used to correlate the six inputs with the corresponding S/P. A 6-3-1 architecture trained to 90+% yielded consistent predictions. The trained neural network was then used to estimate future oil production from the Cliff Farms Unit. It is interesting to note that a map of the distribution of known S/P values supports the value predicted for the Cliffs Farm Unit.
Completion Effectiveness in the Shannon Formation of the Jepson Draw and Holler Draw Fields, Powder River Basin, Wyoming
Authors: Scott W. A. , Guice W. R. 
Published: December 2007

Abstract
The Jepson and Holler Draw fields are located in the Powder River Basin of northeastern Wyoming. The fields were discovered in 1974 and produce 36° API oil from the Shannon sandstone. The Shannon is a 20 foot thick barrier island deposit that occurs between 9,650-10,025' TVD. The reservoir is currently undergoing pressure support from water injection. All producing and injecting wells need to be hydraulically fracture stimulated to produce or inject at adequate rates. Current activity in Jepson and Holler Draw consists of in-fill drilling of new producers as well as restimulation of old producers. Various job designs, fracturing fluid systems, and proppant types have been tried.
This paper analyzes well performance and the effectiveness of fracture stimulations in the Jepson and Holler Draw fields. Information from stimulation pressure histories was examined with several fracture simulators to predict overall fracture length from the various treatments. Daily post-frac production was then evaluated using the reciprocal productivity index (RPI) graphical production-analysis method and combined with analysis from pressure build-up tests to determine permeability-height (KH) and effective infinite conductivity fracture length. The overall fracture length was then compared to the effective infinite conductivity fracture length using reservoir simulation to examine possible explanations for the difference in the two lengths. This comparison was used to draw conclusions about how job design, fracturing fluid systems, and proppant types affected the well performance.
How Proppant Slugs and Viscous Gel Slugs Have Influenced the Success of Hydraulic Fracturing Applications
Authors: McDaniel B. W. , Stegent N. A. , Ellis R. 
Published: December 2007

Abstract
When hydraulic fracturing techniques are used to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. These problems may be related to the perforation entry or to the fracture width in the immediate vicinity of the wellbore. It has often been concluded that insufficient width generation in the NWB area is the result of the fracture having a very tortuous (rapidly turning or twisted) path for the first few inches or feet before adopting its generally planar shape after it grows beyond the wellbore area. In other cases, the inadequate width problem may result from the generation of several independent fracture planes instead of only one (or a few). During the early 1990's, the oil industry began to consider these problems more seriously, and many operators now use techniques to mitigate such problems before or during a fracture stimulation. The completion plan must sometimes be altered to reduce the occurrence of similar problems in future wells completed in a particular reservoir. Proppant slugs and viscous gel slugs have helped remediate this problem during several applications throughout the world.
Contrary to what we would like to believe, proppant and/or viscous gel slugs do not cure every premature screenout. Of course, some people still believe that these slugs would prevent every premature screenout if they were applied properly for the particular problem. If economics were not a real-life consideration, and every completion could be treated as an experiment, that position might be valid. In today's oil and gas exploration environment, the more practical constraints of "economic benefit" present several limitations. This paper discusses these "slug" techniques and their evolution in recent years. It also presents some of the current state-of-the-art methodologies being used. We also offer practical limits to be considered for use with these techniques. Several case histories are presented as illustrations, and suggestions for alternate completion techniques are discussed.
Friction Pressure Correlation for Guar-Based Hydraulic Fracturing Fluids
Authors: Pandey Vibhas J. 
Published: December 2007

Abstract
Accurate prediction of tubular frictional pressure is an important aspect in design, planning and execution of any hydraulic fracturing operation. Majority of correlations available to predict the tubular friction pressures are based on laboratory generated data. The results from such tests have to be scaled up to predict real time solutions. A novel way to develop such correlation based on actual field data is discussed in this paper. Real time data was obtained for over 300 hydraulic fracturing jobs that were pumped using the Carboxymethylhydroxypropyl guar (CMHPG) fluid systems. This data was analyzed using Fanning friction factor and generalized Reynolds number. Both of these dimensionless entities were modified to accommodate the effects induced by polymeric fluids. Results obtained from the new correlation were able to predict the average surface pressures within 4% of the measured values for over 90% of the data. These results were also compared with a few existing correlations and encouraging conclusions were drawn. Pressure predictions from the new correlation were routinely verified in the field and it was observed that predicted pressures matched the actual in a reasonable range of accuracy.
Plunger-Lift Optimization by Monitoring and Analyzing Well High Frequency Acoustic Signals, Tubing Pressure and Casing Pressure
Authors: McCoy Jim , Rowlan Lynn , Podio A. L. 
Published: December 2007

Abstract
Plunger Lift operations are difficult to optimize due to lack of knowledge of tubing pressure, casing pressure, bottomhole pressure, liquid accumulation in the tubing and location of the plunger. Monitoring the plunger position in the tubing helps the operator (or controller) to optimize the removal of liquids and gas from the well. The plunger position can be tracked from the surface by monitoring acoustic signals generated as the plunger falls down the tubing. When the plunger passes by a tubing collar recess, an acoustic pulse is generated that travels up the gas within the tubing. The acoustic pulses are monitored at the surface, and are converted to an electrical signal by a microphone. The signal is digitized, and the digitized data is stored in a computer. Software processes this data along with the tubing and casing pressure data to display plunger depth, plunger velocity and well pressures vs. time. Plunger arrival at the liquid level in the tubing and plunger arrival at the bottom of the tubing are identified on the time plots. Inflow performance is calculated. Software displays the data and analysis in several formats including a graphical representation of the well showing the tubing and casing pressures, plunger location, gas and liquid volumes and flow rates in the tubing and annulus, and inflow performance relationship at operator selected periodic intervals throughout the cycle. A field case is presented to show how this information is applied to optimization of Plunger Lift operations.
Saturation Height Methods and Their Impact on Volumetric Hydrocarbon in Place Estimates
Authors: Harrison B. , Jing X. D. 
Published: December 2007

Abstract
The paper reviews four of the more popular saturation-height methods employed in the oil and gas industry, namely those proposed by Leverett, Johnson, Cuddy and Skelt. The advantages and drawbacks of each method are highlighted. Each technique is compared by investigating how accurately they model the saturation-height profiles of a Palaeocene oil well from the UK Central Graben and a Permian gas well from the UK Southern North Sea. Both wells have complete data sets including conventional core, SCAL and a comprehensive suite of electric logs. Besides comparing each of the methods on a well basis, the paper applies the resultant saturation-height relationships to the reservoir structures to see the effect on the computed hydrocarbon-in-place estimates. By moving to an areal field-wide basis, the effects of reservoir structural relief and the relative importance of the transition zone modelling is brought into focus.