bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Submersible Lift Operations in Gassy Horizontal Wells, Pearsall Field, Texas
Authors: Freet T. G. , McCaslin K. P. 
Published: December 2007

Abstract
Oryx Energy Company has drilled, completed, and produced over 150 horizontal Austin Chalk wells in the Pearsall Field of South Texas. Although rod pumping is the predominant means of artificial lift for these wells1, selected wells are equipped with, submersible pumps to maximize production in a competitive reservoir. In 1989, the first submersible pump was installed in a horizontal well in the Field, and it was quickly discovered that high volume lift operations in gassy, naturally fractured horizontal wells offer unique challenges. These challenges included unpredictable changes in rates, heavy slugging and frequent pump cycling.
This paper reviews experiences with ten submersible installations in horizontal Chalk wells of varied operating conditions. Actual field performance of the installations will be discussed with special emphasis on the iterative design process that led to a dip tube design2 which successfully tackled the aforementioned challenges.
Experimental and Theoretical Investigation of Two-Phase Flow in Horizontal Wells
Authors: Ihara Masaru , Brill J. P. , Shoham Ovadia 
Published: December 2007

AbstractAn experimental and theoretical investigation of the flow behavior in horizontal wells and its interaction with the reservoir was performed. This has been recognized as one of the unsolved, yet most important problems in the production area.A new test facility was designed and constructed, suitable for acquiring data on the relationship between the pressure drop along the well and the fluid influx from the reservoir. The test facility features a 1-in. I.D., 26-ft long horizontal well test section flowing into a 9.2-ft high vertical section. Pertinent preliminary data were acquired.Initial models are proposed which describe the flow behavior in a horizontal well configuration for both the experimental work and field operations. The models use the IPR (Inflow Performance Relationship) approach, the black oil model and mechanistic models for wellbore hydraulics.A sensitivity analysis was performed on key parameters using the model for field operations. Good agreement was found between the model for the experimental work and the preliminary experimental data.A new IPR apart from the extension of the Darcy's law must be investigated extensively to help in the proper design of horizontal wells.
Assessing Risk Reduction Strategies on Offshore Newfoundland Development Projects
Authors: Way K. K. , Fong J. H. , Moynham G. J. 
Published: December 2007

Abstract
Development of petroleum reserves on the Grand Banks offshore Newfoundland commenced in 1990 with the signing of binding agreements relating to the Hibernia development project. Financial and fiscal incentives, which were provided to Hibernia, may not be available to subsequent projects. The possibility of low world oil prices and high development costs depresses the anticipated level of profitability of Grand Banks fields. Potential price volatility, wide ranges in reserves and uncertainty with respect to reservoir performance and costs contribute to the variability of anticipated profitability of such fields.
An illustrative, partially delineated, Grand Banks oilfield is examined in this paper. The field is considered a candidate for development, given satisfactory economic returns and the relevant project risks are identified, quantified and managed. This paper summarizes an approach to assessing the expected level and variability of economic returns on the subject field.
Risk Assessment Approach to Offshore Safety: Part B—The Valhall Firewater System: A Case Study
Authors: Ciaraldi S. W. 
Published: December 2007

Abstract
The use of risk analyses techniques as prescribed by Norwegian regulations is illustrated as it relates to an offshore piping retrofit. The Valhall Field case study of replacement of corrosion prone carbon-steel firewater systems with those constructed of fiberglass piping is reviewed. Key to justification of the deviation from the then existing regulatory restrictions on use of non-metallic piping materials was a risk assessment evaluation of the proposed modification. The risk assessment involved the establishment of performance based function criteria for deluge firewater systems and subsequent systematic evaluations of steel and fiberglass systems under normal operating and explosion/fire accident scenarios. The associated verification test program and specification/quality assurance (QA) developments are also briefly reviewed.
Slug Flow Characteristics and Their Effect on Corrosion Rates in Horizontal Oil and Gas Pipelines
Authors: Sun Jyi-Yu , Jepson W. P. 
Published: December 2007

Abstract
The flow characteristics of slug flow and their effect on the corrosion rates are examined experimentally in a 100 mm diameter, horizontal, Plexiglass pipeline. The system was maintained at a pressure of 2 bars and temperature of approximately 35 °C. After initial tests with oil only and water only, 80% water and 20% oil, and 60% water and 40% oil mixtures were examined. Carbon dioxide was used as the gas. Using the stationary slugs described by Jepsonl1,2, the mean wall shear stress and turbulent intensity at 7 different axial and three circumferential locations were measured using flush mounted TSI hot film anemometer probes. The regions included the film region ahead of the slug, the mixing zone at the slug front, and a short distance into the slug body. The oil, water, and carbon dioxide fractions were measured across a vertical diameter using a sampling probe. Corrosion rates at the top and bottom of the pipe were measured using electrical resistance probes. Pressure gradients across the slug front were also taken.
The results clearly show that the slug front is a highly turbulent region that has large wall shear stresses at the bottom of the pipe. The wall shear stress decreases with circumferential position but increases with increasing oil fraction in the fluids. For a Froude number of 12, the shear stress for water only is 26 N/m2. For the mixture of 60% water and 40% oil a value of 97 N/m2 is attained. These are much greater than anticipated. Instantaneous values are much larger than this. The corrosion rates are much greater than those predicted by usual laboratory methods, such as rotating cylinders or disks. The rates are shown to be greatest at the bottom of the pipe and correspond to the regions of high wall shear. Corrosion rates increase with an increase in oil concentration at the same Froude number. It is concluded that the wall shear stress associated with the slug front is sufficient to continuously remove corrosion products from the pipe wall.
A Transient Multiphase Temperature Prediction Program
Authors: Erickson D. D. , Mai M. C. 
Published: December 2007

Abstract
A computer model has been developed which accurately describes transient heat transfer in buried multiphase pipelines. The model is used primarily to estimate hydrate and paraffin potential during startup, shutdown, and blowdown in subsea oil/gas flowlines. Other uses include specification of minimum temperature requirements for pipeline materials that may be exposed to high-pressure blowdown. The model development is described, and examples of application are presented.
Dynamic Production System Nodal Analysis
Authors: Stoisits R. F. 
Published: December 2007

Abstract
A Dynamic Production System Nodal Analysis (DPSNA) Technique has been developed, verified, and applied to wells’ in the Kuparuk River Field.
This analytical technique combines reservoir performance models, nodal analysis for individual wells, and calculation of pressure drop in the network of surface lines to obtain a global analysis of the production system through time.
Evaluation of the DPSNA Technique was performed using well test data from twenty-five wells in the Kuparuk River Field. Each well in the analysis contained two productive intervals. The DPSNA Technique was able to predict the effect of a producing zone control strategy on oil, gas, and water production from these wells.
Design and Installation of a 20,500-ft Coiled Tubing Velocity String in the Gomez Field, Pecos County, Texas
Authors: Adams L. S. , Marsili D. L. 
Published: December 2007

Abstract
This paper reviews candidate selection, installation design, implementation, and production results of a 20,500 ft coiled tubing velocity string in the G. M. Shelton No. 2, a deep, low pressure, Gomez (Ellenburger) Field gas well.
Perforation Cavity Stability: Comprehensive Laboratory Experiments and Numerical Analysis
Authors: Tronvoll Johan , Morita Nobuo , Santarelli F. J. 
Published: December 2007

Abstract
The paper describes comprehensive laboratory and numerical studies of perforation cavity stability and sand production from a perforation tunnel. Jacketed cores with a cavity simulating a perforation tunnel were loaded in a high-pressure vessel and fluid flow was applied. The cavity deformation and failure were monitored by a cantilever deformation gauge, while produced sand was monitored acoustically and volumetrically at the outlet of the cavity. A cavity stability analysis was conducted using a 3D non-linear finite element model.
The numerical analysis shows that the onset of limited sand production matches the initiation of shear failure at the cavity wall. However, the perforation cavity is still relatively stable in the sense that it does not collapse. The sand production increases with the expansion of the post-failure zone, and the cavity finally collapses if excessive confining load is applied to the sample. The post-failure mechanisms are critical with respect to cavity collapse and sand production problems, which may explain the discrepancy between experimental and analytical results.
Indigenous Microorganisms in Connate Water of Many Oil Fields: A New Tool in Exploration and Production Techniques
Authors: Bernard F. P. , Connan Jacques 
Published: December 2007

Abstract
A microbiological investigation was carried out on 66 water samples taken from producing wells on 24 oil fields. The fields were all of a different nature and located in different places. Many of the samples contained microorganisms and it has been demonstrated that some of their associations do really originate in the connate water concerned and often contain unknown species.
These bacteria differ according to the nature of the geological formations and to the physico-chemical state of the water and the oil found in the various reservoirs. The nutrients which they need and the products of their metabolism thus vary substantially. They have been able to modify the state of oil and gas accumulations quite considerably and may continue to do so.
The result is that practical applications can already be established and there are many other potential uses. Some of them concern exploration and, by analogy, can be used to improve the rate of discovery. Others give rise to the reappraisal of certain aspects of reservoir management, in particular that of biodégradation of hydrocarbons and the aquifer regime. Other aspects concern production and the protection of installations, i.e. the fight against biocorrosion and souring.
Case Histories of Low-Cost Sand Consolidation in Thermal Wells
Authors: Shotts N. J. , Surles B. W. , Fader P. D. 
Published: December 2007

Abstract
A new sand control technology has been developed, patented,1,2 and successfully applied in the Kern River Field, Bakersfield, California, using a modified furan resin. The chemical system is very low cost, thermally stable to 700 °F and does not reduce gross production. It is environmentally safe and inert to oilfield chemicals.
The sand control process involves consolidating formation material during steam stimulation of a well by injecting the treatment chemical mixed with catalyst into the steam. After the steam diluted chemical travels downhole, polymerization occurs on the formation sand grains. Consolidation is completed within a few minutes. Additional shut-in time is not required; the well can be returned to production immediately.
Following successful lab testing3, field tests were conducted in the Kern River Field, Bakersfield, California, using both model test wells and active production wells. The tests determined the optimal treatment conditions for the process. To date, over 100 producing wells have been treated. Results indicate the process reduces sand production and operating costs without reducing gross production.
Sand Control in Wells With Gas Generator and Resin
Authors: Dees J. M. 
Published: December 2007

Abstract
Case histories of 22 treatments with a very new sand control procedure applied in Oryx Energy Company wells are reviewed. An acid curable resin is positioned in the casing across the perforated interval in an incompetent sand formation. A gas-frac propellent tool is placed in the resin. The propellent is fired to generate gas and drive the resin from the casing and into the formation outside the perforations. Resin remaining in the casing is displaced with gas or water to establish permeability to the non-resin phase and subsequent acid overflush ensures set of an oil-wet coating of hard plastic which acts as an external sand control screen. In addition, production rate from the well is frequently stimulated, apparently because fracturing pressures from the gas generator surge perforations clear of formation sand during the resin placement.
A New Solvent for Oilfield Scales
Authors: Paul J. M. , Fieler E. R. 
Published: December 2007

Abstract
Mobil has developed a new solvent to dissolve oilfield scales, including sulfates of barium, strontium and calcium, as well as calcium carbonate. Naturally occurring radioactive material (NORM), which is usually co-precipitated with barium and strontium sulfates, is removed by this solvent. Performance features of the solvent and case histories of field tests are reviewed. Materials compatibility with the solvent and disposal options are also briefly discussed.
High Fracturing Pressures for Shales and Which Tip Effects May Be Responsible
Authors: Gardner D. C. 
Published: December 2007

Abstract
Frequently, net treating pressures (pressure in excess of closure stress) observed during hydraulic fracturing, are significantly greater than what is predicted by industry fracturing simulators. Elevated net pressures have been attributed to various fracture tip phenamena, some of the more popular of these being: 1. high fracture toughness, 2. "dry zone," a zone near the fracture tip where injected fluid is excluded, 3. non-linear or inelastic effects resulting in dilation or reduced fracture widths.
A study of the above effects on fracture widths and pressures was conducted for symmetric radial ("penny") fractures. A rigorous solution method was developed which permitted characterization of the extent of a "dry zone" and it’s effect on width and pressure. Results indicate that the size of this zone is largely controlled by the pressure within the zone and by the pressure gradient of the injected fluid that is next to it. Therefore, conditions which promote large pressure gradients such as high viscosity, large moduli and high injection rates, also create larger "dry zones." However, the width and pressure near the wellbore were found to be essentially independent of the size of the "dry zone."
The effects that dilatant behavior, possibly caused by plasticity or micro cracking, might have on elevating fracturing net pressures was simulated using an approximate inelastic solution. This solution method modifies the elasticity equation by a "stiffening" function to effectively reduce the width such that the greatest relative reduction occurs near the crack tip. Net pressures and widths near the wellbore can be considerably greater than those obtained with the elastic solution (widths are still greater even in those cases where toughness is elevated to match the net pressure). Bottom hole pressure data was obtained during extensive fracture testing of shales/mudstones in the North Sea. A radial fracturing model simulating inelastic conditions, was found to better predict fracturing pressure responses than its elastic counterpart.
Recovery Optimization in a Multi-Reservoir Offshore Gas Field With Water Influx
Authors: Hower T. L. , Lewis D. R. , Owens R. W. 
Published: December 2007

Abstract
A detailed engineering and geologic evaluation of an offshore Gulf Coast gas reservoir with water influx is presented. The study was undertaken to analyze various production management strategies in order to optimize the ultimate recovery of the reservoir given the detrimental effects of the water influx.
Without implementing any reservoir management techniques, the recovery factor of the reservoir is estimated at 66%, much lower than would be expected under volumetric depletion performance. It is demonstrated that producing high volumes of water from downdip wells and adding an additional well high on the structure can significantly increase the ultimate gas recovery from the reservoir. This is achieved by lowering the reservoir pressure which liberates trapped residual gas and by recovering mobile attic gas. However, accelerated gas production does not appear to be beneficial in this particular case due to a reduced volumetric sweep efficiency associated with the accelerated rate case. Economic analyses show that recompletion of an additional well at a higher structural position is the optimum strategy for this particular reservoir. Due to the limited extent of the aquifer, this single well will effectively lower reservoir pressure, liberate gas trapped at residual saturation and recover mobile gas remaining at the top of the structure.
An Integrated Approach To Evaluate the Upside Potential of a Mature Field, Countyline Unit, Sho-Vel-Tum Field, Oklahoma
Authors: Zambrano L. G. , Killberg G. C. , Kendall J. J. 
Published: December 2007

Abstract
Significant additional oil potential has been identified in the Countyline Unit, Sho-Vel-Tum field, Oklahoma. The study is an integrated multidisciplinary approach which incorporates: 3D seismic to define the reservoir structure and fault blocks; detailed reservoir characterization to define the geometry and internal architecture of each "flow unit" in each fault block; numerical simulation to determine reservoir performance and optimum recovery strategy.
Performance and Analysis of Three-Phase Capillary Pressure Curves for Drainage and Imbibition in Porous Media
Authors: Kalaydjian F. J-M. 
Published: December 2007

Abstract
Three-phase capillary pressure curves measured in both drainage and imbibition on an outcrop water wet sample and on unconsolidated water wat cores, under ambient conditions, are presented.
These measurements show that both drainage and imbibition capillary pressures depend on the three saturations.
The impact of the spreading coefficient S, measuring the ability for oil to spread on water in presence of gas, on three-phase capillary pressure curves is shown.
Its effects on both drainage and imbibition capillary pressure curves are quantified and supported by pore scale experiments performed in glass capillary tubes and in glass network micromodels.
Improving the Centrifuge Technique by Measuring Local Saturations
Authors: Chardaire-Riviere Catherine , Forbes Pierre , Zhang Jian Feng , Chavent Guy , Lenormand Roland 
Published: December 2007

Abstract
A significant new improvement in the centrifuge method is proposed. It consists in continuously recording the local saturation variation by using an ultrasonic device at different locations along the core, while centrifuging at any given time.
The experimental procedure consists in recording flight times of ultrasonic waves at three locations along the core and then determining local saturation by a simple specific calibration, which leads to correspondence between the ultrasonic signal and saturation.
By using this procedure, direct determinations of oil/brine capillary pressure curves are obtained by studying equilibrium regimes. Meanwhile, local saturation measurements make it possible to investigate the transient regime in order to compute relative permeability curves. Then relative permeability curves are estimated by using a least-squares technique.
The relative permeability curves representative of the centrifuge experiment are in good agreement with the curves obtained by using the unsteady-state technique for a sandstone sample.
Anguille Marine, a Deep-Sea Fan Reservoir Offshore Gabon: from Stochastic Modelling Toward History Matching.
Authors: Giudicelli C. B. , Alabert F. G. , Massonnat G. J. , Corre Bernard 
Published: December 2007

Abstract
The Anguille Marine field, located offshore Gabon, lies in a complex heterogeneous turbiditic formation. A geological/geostatistical approach was applied to create 3D images of the reservoir. The flow simulation of the 25 years of production history was performed after a severe upscaling from more than two millions gridblocks to 11,000 ones. The difficulties in matching the observed behaviour of the field raised several questions regarding the upscaling process, the geological model and the relationship between the two. The use of partial models helped greatly in tracking the origin of the discrepancies. The choice of the aggregation rate proved to be too important in this case of heterogeneity. It should be optimized when dealing with strongly heterogeneous stochastic models.
Waterflood-Induced Fracturing: Water Injection Above Parting Pressure at Valhall
Authors: Eltvik Petter , Skoglunn Tom , Settari Antonin 
Published: December 2007

Abstract
During a three year waterflood pilot program at the Valhall field, injection at a pressure higher than the Formation Parting Pressure (FFP) was employed to improve inject¡vity. Due to concerns about premature water breakthrough and reduced sweep efficiency, an engineering study was performed simulating the dynamic growth of the induced fracture. The work provided a better understanding of the dominant physical processes occurring during the Valhall waterflood pilot and gave a tool for predicting future performance.
Specialized hydraulic fracturing software, capable of modelling dynamic fracture propagation, was used. The fracturing model included the effects of 2-dimensional leak-off, fluid mobility, waterflooded region compressibility, rock and fluid thermal effects and poroelastic back stress effects. The capability of interfacing the predicted dynamic fracture to a thermal reservoir simulator was also demonstrated as a practical means of modelling water injection above FPP in single and dual reservoir descriptions.
The work concluded that minimal water breakthrough effects would occur until induced fracture lengths exeeded 20 to 40 percent (depending on reservoir media) of the interwell distance. However, with a voidage ratio of unity, the induced fracture length at Valhall will not stabilize with time due to fluid mobility effects. It was also found that the poroelastic back stress dominates over the thermal back stress in a chalk reservoir like the Valhall field.
In September 1991, water breakthrough in an offset producing well occured and the initial study has since been expanded to include matching of observed watercut performance, pulse testing and recent step rate tests. The results highlight the importance of the dynamic induced fracture as well as other factors such as pressure dependent permeability and a dual porosity reservoir description.