bluuebunny/crossref_metadata_2025_split huggingface dataset:
Best Practice for the Distribution and Metering of Two-Phase Steam
Authors: Hong K. C. , Griston Suzanne 
Published: December 2007

Summary
For a steamflood project to be successful, steam of predetermined quality and rate must be delivered to each injection well. This paper presents a comprehensive review of devices and methods that are aimed at providing accurate distribution and metering of two-phase steam. A best practice recommended for optimizing the distribution and metering process consists of several tools and procedures, including the following.
Using impacting tees, with or without insert devices, to maintain uniform steam quality throughout a piping network. Controlling the steam rate at each wellhead using a critical flow choke, with a straight-bore or tapered-bore bean insert. Periodically measuring steam rate and quality at each injector using a two-phase separator vessel. Monitoring wellhead rates on a biweekly or monthly basis using measured steam temperatures upstream and downstream of the wellhead chokes.
Crossflow in Fractured/Layered Media Incorporating Gravity, Viscous, and Phase Behavior Effects
Authors: Dindoruk Birol , Firoozabadi Abbas 
Published: December 2007

Summary
Crossflow across the interfaces of layered reservoirs, and between matrix blocks and fractures in fractured reservoirs may be very pronounced. The literature emphasizes viscous crossflow, however, crossflow due to gravity may be more significant.
In this paper, the crossflow due to various effects in layered and fractured media are presented. The examples selected for the layered media show that most of the oil is first transferred from the low permeability to the high permeability layer and then produced. The examples for fractured media reveal a significant contribution of crossflow to recovery performance. The fractured-media examples imply that a real challenge exists to perform compositional simulation of fractured reservoirs.
Heterogeneities Modeling and Uncertainty Quantification of the Gullfaks Sør Brent Formation In-Place Hydrocarbon Volumes
Authors: Linjordet Arne , Nielsen P. E. , Siring Erling 
Published: December 2007

Summary
The Gullfaks Sør oil- and gas-filled Brent reservoir can be divided into 14 fault Segments, five of which are penetrated by wells that have proven hydrocarbon columns between 32 and 316 m. The uncertainties in gas and oil in-place volumes have delayed the time from discovery in 1978 to the current partial development plan that was submitted to the Norwegian authorities in 1995 for development of the oil reserves. This paper describes the method used for modeling fault-segment reservoir heterogeneities and the method of quantifying the distribution of oil and gas accumulations. The final product is the most likely stock tank oil initially in place/gas initially in place (STOIIP/GIIP) with reliable high- and low-volume estimates for management decision making.
We evaluated the initial reservoir fluid pressures and fault-sealing properties together with observed internal reservoir barriers to vertical fluid flow and several fluid-contact observations. We established a quantification of the oil-leg thicknesses, including uncertainty ranges, on the basis of the field gas- and water-pressure gradients and the fluid densities. This quantification had to honor the various fluid contacts, the fluid gradients, and log observations, such as water up to, gas down to, and geochemical core analysis.
We evaluated the degree of communication between drilled fault Segments by determining probabilities of static-pressure communication between the drilled and undrilled fault Segments and between the various reservoir units across the faults. We assessed communication of fluid flow across faults by evaluating the clay smear (amount of clay material in relation to the fault planes) and juxtaposition relations of the reservoir units across faults.
We used a Statistical approach to quantify the uncertainty in the proven and probable in-place Gullfaks Sør Brent formation hydrocarbon volumes for field-development decision making. A geostatistical program designed to handle laterally varying uncertainties was used for quantifying uncertainties in the seismic Interpretation, velocity model, depth conversion, isochores, and fluid contacts. To evaluate the petrophysical uncertainties and the probabilities for gas- or oil-filled reservoir Segments, we used a classical Monte Carlo Simulation method. The combined use of geostatistical analysis and Monte Carlo Simulation has proved to be a useful and fast approach for modeling the Gullfaks Sør field.
First Horizontal Water Injectors in Prudhoe Bay Field, Alaska
Authors: Bodnar D. A. , Clifford P. J. , Isby J. S. , Lane A. C. , Loveland Richard , Seymour L. I. , Urban D. M. , Shultz S. M. , Walz G. S. 
Published: December 2007

Summary
Water injection into horizontal wells is a new and distinct technology, where success will often depend on the management of thermal fractures. This paper describes the background, planning, drilling, completion, and results of the first two high-angle water injection wells in the Prudhoe Bay field. The procedures described resulted in re-establishing injection in the correct zone, achievement of target rates and good injection profiles.
Composition and Phase Changes in Testing and Producing Retrograde Gas Wells
Authors: Novosad Zdenka 
Published: December 2007

SummaryDepletion of two retrograde gas reservoirs is analyzed with a compositional simulation model, focusing on changes in well performance caused by liquid dropout. In one case presented, a low-permeability reservoir at its dewpoint, transient effects are shown to contribute more to well productivity decline than liquid dropout. This is demonstrated by comparing the well productivity with that of an otherwise identical dry gas well. The evolution of the near-well liquid bank is interpreted in terms of compositional changes occurring in the fluid once the flowing bottomhole pressure falls below the dewpoint. The thermodynamic path of depletion is shown to be a function of radial distance (i.e., the pressure regime), and to be considerably more complex than implied by constant volume depletion (CVD) experiments. Near-well fluids undergo a transition from a retrograde gas to a volatile oil early in the depletion, passing through a critical composition in the process. This brings about large changes in phase properties and their saturations, and thus flow behavior, with even a small pressure change. This has implications for interpretation of pressure buildup and falloff tests on these wells. At a later stage in the field life, near-well fluids are converted from a volatile oil to a dry gas (passing through a critical composition again). With time, fluids in the reservoir interior undergo similar qualitative changes. Only the fluids near the reservoir edge follow a CVD path. The described phenomena are shown to occur in a higher-permeability reservoir also as soon as the bottomhole flowing pressure (BHFP) falls below the saturation pressure.
Developing and Implementing a Failure-Analysis Process To Optimize Well-Servicing Operations
Authors: Yonke Charles Lwanga , Araujo F. G. , Koehler K. D. , Strawn T. T. 
Published: December 2007

Summary
Breakthrough cost reductions can be achieved through the use of an effective failure-analysis and control process. In 1995, CalResources designed and implemented a root-cause failure-analysis process for well-servicing operations. Important elements of the process include a structured process flow, a six-step failure-analysis model, tools for failure control (databases of well-failure codes and pump details, pump application tables, well-servicing economics), and meaningful tracking measures with targets. This process has been a key strategy to reduce expenses and increase equipment run time. Well pulls decreased by 33% from the previous year, repeat pulls decreased by 42%, well-servicing expenses decreased by 16%, and producer run time increased by 15.5%. Process implementation was achieved through operator empowerment and buy-in. Empowerment was developed through knowledge, with formal and informal sessions serving as forums for continuous training, practice, and feedback. This paper outlines the elements of the failure-analysis process developed, and discusses the implementation steps that made it successful.
Does Gauge Placement Matter in Downhole Transient-Data Acquisition?
Authors: Kabir C. S. , Hasan A. R. 
Published: December 2007

Summary
Transient pressure data are often collected at various points in the wellbore, including the wellhead, for test interpretation. When data gathering takes place at a point other than the midpoint of producing (MPP) interval, either inadvertently or by design, serious interpretation problems may arise because of wellbore thermal effects. Many field tests conducted on gas, oil, and water injection wells show the severity of this wellbore-induced problem. This paper explores the consequences of thermal effects upon test analysis in some cases and presents new insights into both data collection and their interpretation. Existing methods do not capture the borehole physics to allow us to study this problem.
We present interesting synthetic and field cases. One field example shows that pressure actually can decrease during buildup tests in a gas well in a high-transmissivity reservoir. In this test, data were collected about 1,200 ft above the MPP in a 9,000-ft well because of mechanical restrictions downhole. We reproduced this observed behavior with the simulator. Pressure decrease in a buildup is caused by the dominating influence of thermal diffusion over pressure diffusion in a high-transmissivity system when measurements are made away from the MPP For the same reason, pressure increases during a drawdown test. Equally important, results of the computation show that even if data were collected at the MPP, the gauge's ability to resolve small changes in pressure would have been tested severely.
Reservoir Modeling and Simulation of a Middle Eastern Carbonate Reservoir
Authors: Sibley M. J. , Bent J. V. , Davis D. W. 
Published: December 2007

Summary
A giant Middle Eastern reservoir was modeled and history matched during reservoir simulation. The model was used to help predict reservoir performance under various scenarios and to evaluate the impact on production rates, ultimate recovery, and economics. Implementation of an infill, extension, and pressure-maintenance plan is in progress. This model overcame shortcomings of previous models of this reservoir through detailed integration of geologic, geophysical, and engineering data. Among the data incorporated were slabbed core, thin-sections, core analyses, seismic, isotope, open-hole logs, thermal-decay-time (TDT) logs, repeat formation tests (RFT's), field-pressure surveys, oil and water production data, and production tests. Significant modifications were made to internal and external reservoir architecture, and a diagenetic barrier (DB) was discovered that is the primary barrier to aquifer support. Results of the study include increased booked reserves and production rates, additional infill wells, two reservoir extension area discoveries, and the design and implementation of a pressure-maintenance program.
Multiphase-Pump Field Trials Demonstrate Practical Applications for the Technology
Authors: Dal Porto D. F. , Larson L. A. 
Published: December 2007

Summary
This paper presents the results of two multiphase-pump field trials. One field trial was conducted offshore on a platform in the Gulf of Mexico (GOM). It is a low-pressure boost (100 psi) application involving gas-lifted wells. The other field trial was conducted onshore in an oil field in Alberta, Canada. This multiphase pump was designed for a high-pressure boost (850 psi) capability with primarily rod-pumped wells feeding the suction of the pump.
The offshore pump was sized to handle the flow from one well. By lowering the back pressure on the well, increased production was realized. The increased flow from one of the wells far surpassed the predicted quantity. Early problems with the double mechanical seal system were overcome and a new, simplified single mechanical seal system has been designed and installed.
The onshore multiphase pump clearly demonstrated that a twin-screw pump can operate reliably in a field environment, even under severe slug flow conditions. The trial indicated that a considerable portion of the liquid in the recycle stream (required because of the high gas fraction of the multiphase fluid from the field) flashes into gas, which occupies more volume in the pump than if it remained liquid. This decreased the capability of the pump to handle net flow from the field. These conditions motivated a re-evaluation of the pump-sizing techniques.
Performance data and lessons learned information are presented for both field trials.
Bridging Adsorption of Flexible Polymers in Low-Permeability Porous Media
Authors: Zitha P. L. J. , Botermans C. W. 
Published: December 2007

Summary
Polymers used in water control are believed to always invade low-permeability layers to a sizable extent, impairing oil production. For this reason, water-shutoff treatments are usually combined with zone isolation; however, zone isolation is impractical in most wells, and the polymer must be injected through the whole open interval. Small invasion of low-permeability layers must then be ensured by some intrinsic property of the polymer. This idea was proved in a recent study, where polymer penetration in low-to-medium permeability cores was shown to be much smaller than usually predicted. This effect was explained by the bridging adsorption of stretched chains across the smallest pores. This paper develops a mathematical model for this phenomenon, and checks its true effect on placement by use of a prototype reservoir. The simulations confirm that polymer penetration in low-permeability layers decreases greatly when bridging adsorption is present.
A 3D Field-Scale Streamline-Based Reservoir Simulator
Authors: Batycky R. P. , Blunt M. J. , Thiele M. R. 
Published: December 2007

Summary
We present a new streamline-based simulator applicable to field scale flow. The method is three dimensional (3D) and accounts for changing well conditions that result from infill drilling and well conversions, heterogeneity, mobility effects, and gravity effects. The key feature of the simulator is that fluid transport occurs on a streamline grid rather than between the discrete gridblocks on which the pressure field is solved. The streamline grid dynamically changes as the mobility field and boundary conditions dictate. A general numerical solver moves the fluids forward in space and time along each streamline. Multiphase gravity effects are accounted for by an operator-splitting technique that also requires a numerical solver. Because fluid transport is decoupled from the underlying grid, the method is computationally efficient and very large time-steps can be taken without loss in solution accuracy.
We present results of the streamline-based simulator applied to tracer, waterflooding, and first-contact miscible (FCM) displacements in two and three dimensions. Where possible, comparisons with conventional methods indicate that the streamline model minimizes numerical diffusion and is up to two orders of magnitude faster. We also demonstrate the efficiency of the method on a field-scale, million-gridblock, 36-well waterflood that includes a pattern-modification plan to improve oil recovery. Last, we present results of the method applied to the House Mountain waterflood in Canada.
Pressure and Composition Effect on Wax Precipitation: Experimental Data and Model Results
Authors: Pan Huanquan , Firoozabadi Abbas , Fotland Per 
Published: December 2007

Summary
Wax precipitation is often studied using stock-tank oil. However, precipitation may be very different in well-tubing and production facilities because of the effects of pressure and composition. For example, the cloudpoint temperature may decrease as much as 15 K from atmospheric pressure to a saturation pressure of 100 bar mostly because of the solubility of light hydrocarbons into the oil (i.e. because of composition effect).
In this study, the cloudpoint temperature (CPT) at live-oil conditions and the amount of the precipitated wax at stock-tank-oil conditions are provided for four crudes. For one of the crudes, the effect of dilution with C1, C3, n-C5, n-C7, n-C10, n-C12, and n-C15 on the CPT is measured. A modified multisolid-wax model is used to study the effects of pressure and composition on wax precipitation. The experimental data and model results reveal that the CPT rises with the increase of the pressure and decreases when a crude is mixed with light hydrocarbons (such as C1, n-C5, and n-C7).
Pilot Tests of Alkaline/Surfactant/Polymer Flooding in Daqing Oil Field
Authors: Wang Demin , Zhang Zhenhua , Cheng Jiecheng , Yang Jingchun , Gao Shutang , Li Lin 
Published: December 2007

Summary
After the success of polymer flooding in Daqing, two alkaline/surfactant/polymer (ASP) floods were conducted to increase oil recovery further, to study the feasibility of ASP flooding, and to provide technical and practical experience for expanding the ASP pilots. The crude oil of both pilots has a high paraffin content and low acid value. After extensive screening, an ASP system with very low surfactant concentration and wide range of ultralow interfacial tension (IFT) with any concentration change of the three components was determined for each pilot. Coreflooding and numerical simulation show more than 20% original-oil-in-place (OOIP) incremental recovery by ASP over waterflooding for both pilots. The ASP flood pilot tests are technically successful and, on the basis of preliminary evaluation, economically feasible; therefore, much larger-scale ASP-flooding field tests are planned in Daqing oil field in the near future.
Development of a Low-Cost FPSO for Service in the Zaafarana Oil Field, Egypt
Authors: McCarthy Tomás 
Published: December 2007

Summary
This paper presents an overview of the Zaafarana oil field development and a more detailed account of the conversion of its floating production, storage, and offloading facility (FPSO), concentrating on the contractual and cost elements of that work.
The development presented a series of unique challenges and set a number of firsts. These included the redeployment of an internal turret mooring system, use of a turret-based electrical-cable jumper system, and the permanent use of cable-deployed electric submersible pumps in the gravel-pack well completions.
The Zaafarana FPSO was delivered with change order work amounting to less than 3% of the contracted price and within 10 days of schedule (adjusted for permitted delays). Award of contract to first oil was 1 year. This was achieved through the adoption of a low-cost approach, concentrating on obtaining only essentials, with a minimum of preferential engineering. Flexibility of approach to problem solving and maintenance of a nonconfrontational attitude between contracting parties proved essential.
Field Experiences and Guidelines for Use of Nonviscous Fluids in Frac-Pack Operations
Authors: Capra Laura , Ripa Giuseppe , Ferrara Giovanni , Travis Robin 
Published: December 2007

SummaryIn the Adriatic offshore area, conventional cased-hole gravel-pack completions have generally produced low flow efficiences (10 to 50%) from the multilayered reservoirs of low-to-medium gas permeability (1 to 50 md). This has been attributed to the poor communication between the wellbore and the producing layers, caused by limited exposure of the interval and poor filling of the perforation tunnels with gravel. This is confirmed by openhole gravel-pack (OHGP) completions where much higher flow efficiencies are observed.The frac-pack technique, which combines gravel-pack and fracturing technologies, can improve communication between the layers in perforated completions by creating a vertical fracture with high conductivity and the injectivity necessary to fill the perforation tunnels. In addition, any existing near wellbore damage will be bypassed.This paper reviews the field experience gained from over 80 frac-pack operations that have been performed during the last 2 years in the thin, interbedded layers of poorly consolidated sand and shale commonly found in the Adriatic area. Owing to their relatively low permeability, these formations can be fractured with nonviscosified fluids at pump rates less than 1 bbl/min. Consequently, completion brine was selected as the treating fluid. To reduce operational time and costs, the frac-pack treatments were carried out with the gravel-pack assembly in place and injection rates of up to 7 bbl/min were used with gravel concentrations staged from 1 to 4 lbm/gal. Fluid losses were encountered after the frac-pack treatments and were controlled by spotting a small pill of drill-in fluid (containing calcium carbonate) that was sized to bridge inside the screens. This paper presents the production performance of the frac-pack completions and establishes guidelines for future applications of frac-pack operations in similar reservoirs.
Amphoteric Polymer Improves Hydrocarbon/Water Ratios in Producing Wells—An Indonesian Case Study
Authors: Stanley F. O. , Tanggu P. S. , Hardianto _ , Marnoch Ewen 
Published: December 2007

Summary
Exorbitant water production is constantly burdening the oil industry, especially as lifting and facility costs rise and disposal of produced water becomes increasingly expensive and environmentally sensitive. An amphoteric polymer material (APM), previously described in Ref. 2, has been successfully applied in Indonesia. This product reduces water cut and very often increases hydrocarbon production by effectively reducing the permeability to water without significantly changing the formation permeability to hydrocarbons. This paper reviews the mechanism, application, and associated laboratory results by which the APM polymer reduces water cut, with a primary emphasis on Indonesian case histories.
The product can successfully and economically reduce water production, often with the added benefit of increased hydrocarbon production. Results also indicate that high-permeability sandstone reservoirs with water-production problems can benefit from APM treatments. Laboratory and field results show good product application under high-shear situations and at temperatures up to 275°F.1,2,4 Careful candidate selection and good placement techniques, in conjunction with production logging to determine water location, are important to the success of APM jobs.
The Mustique/Shasta Project: A Small Operator's Deepwater Management Challenge
Authors: Huber D. S. , Smith C. D. 
Published: December 2007

Summary
The project-management approach taken by a small independent oil company's first venture into subsea is described from initial business plan scoping economics to putting the wells on-stream. Hardy Oil & Gas U.S.A. Inc. (now Mariner Energy Inc.) wanted to remain strictly a producer without a large internal engineering staff. However, they were averse to delegating the project management or design responsibility to an outside company. The solution was a project-management-team approach with senior representatives of the major vendors being directly involved in the upfront design process. The vendor-selection process included all the major contracting methods including turnkey, partnering, teaming, and cost plus.
The Mustique/Shasta project in the Gulf of Mexico included three wells in 800- to 1,100-ft water depth tied back 9 to 12 miles to two platforms in 650-ft water depth.