bluuebunny/crossref_metadata_2025_split huggingface dataset:
Long-Term Testing of Vertically Fractured Gas Condensate Wells
Authors: Søgnesand S. 
Published: December 2007

ABSTRACT
This paper examines the effect of retrograde condensate blockage on long-term well performance of vertically fractured gas condensate wells. A method is presented to correct the effect of condensate blockage using the concept of time-dependent skin factor. Also documented is important differences in productivity loss due to condensate blockage for vertically-fractured and radial, unstimulated wells.
The effects of fluid properties and relative permeabilities are considered, as is the effect of production mode — i.e., constant-rate versus constant-sandface-pressure production. Results are based on numerical simulations using a fine-grid, vertical-fracture geometry model with a modified black-oil PVT formulation.
The stimulus for the work has been the historical performance of several North Sea condensate fields producing from chalk formations. Well performance history from these wells, which have been stimulated by large acid treatments, indicates no appreciable deterioration of well performance (i.e., skin) during the first ten years of depletion. Also, the author has not found any publications on productivity loss due to condensate blockage in vertically fractured wells, despite the common practice of stimulation in low-permeability gas condensate reservoirs.
The results show considerable differences in long-term productivity between stimulated and non-stimulated gas condensate wells. The argument is made that moderate-permeability wells, which otherwise would not require stimulation, may be prime candidates for stimulations to reduce or eliminate the effect of condensate blockage. Stimulation of such wells would be justified mainly on an analysis of the percentage of well pressure losses that are caused by reservoir and near-wellbore effects, relative to total pressure losses including flow through tubing.
Analysis of Buildup and Drawdown Tests With Variable Wellbore Storage and Skin
Authors: Soliman M. Y. , Hedayati S. , Daneshi T. 
Published: December 2007

AbstractThe partial differential equation describing the flow of fluid in a porous media was derived by combining the continuity equation (material balance), Darcy's equation of flow and the equation of state. The partial differential equation was linearized by neglecting high order gradient terms such as (∂2p/∂r2). The resulting partial differential equation is the well known parabolic diffusivity equation. This diffusivity equation which incorporates the effect of welibore storage and skin factor on the inner boundary condition has been solved1 and the solution is used to analyze the pressure drawdown. The pressure buildup testing theory was derived from the pressure drawdown theory described above.By definition, a pressure buildup test consists of two parts; the drawdown (flow) and shut-in periods. Traditionally, the equations defining a buildup test were derived using the diffusivity equation utilizing the principle of superposition. Thus it was implicitly assumed that the equations governing fluid flow were linear and that constancy of inner boundary conditions prevail throughout the drawdown and shut-in periods. Although these conditions are usually met, certain conditions may exist that prevent application of superposition. For example, requirement of linear partial differential equation which is essential for the application of superposition, is not fulfilled when the turbulent condition prevails during drawdown period. During the shut-in period however, the fluid velocity inside the reservoir diminishes quickly and turbulent effect ceases to exist. This turbulent flow is known to occur in high permeability gas reservoirs producing at high rates.The turbulent flow is usually accounted for by modifying the fluid flow equation for laminar flow by adding turbulent flow term.
An Expert Advisor Program for SSC and NACE MR-01-75
Authors: Craig B. D. , Thompson R. S. 
Published: December 2007

Abstract
Produced petroleum fluids containing hydrogen sulfide (H2S) gas are often referred to as "sour". Hydrogen sulfide gas in the presence of free water can cause certain metal alloys to crack which is referred to as Sulfide Stress Cracking (SSC). SSC of metals is a serious safety issue for the petroleum industry and is addressed by the NACE (National Association of Corrosion Engineers) MR-01-75 document1 which establishes requirements for metallic materials suitable for sour environments. Sour service materials selection is a complex problem often facing personnel not experts in this area.
Since SSC and the NACE MR-01-75 document are not easily understood by most petroleum engineers, an expert advisor computer program was developed to integrate expert comments, SSC fundamentals, key metallurgy concepts, and NACE MR-01-75 requirements.2 This program is termed an expert advisor rather man an expert system because it seeks to teach the knowledge rather than simply provide expert answers. A novice user is able to proceed through a structured tutorial to establish the necessary fundamentals on metallurgy, SSC technology, and NACE MR-01-75 requirements necessary for informed use of the NACE document. More experienced users can proceed directly to the expert system portions of the system for direct evaluation of an alloy specification. A general survey option is available within the expert system portion to evaluate NACE requirements in a general context without being limited to the specifics of a given alloy specification.
This software demonstrates that expert systems technology can be applied to SSC and NACE MR-01-75 to provide expert communication to users.
Compositional Reservoir Simulation: A New, Efficient, Fully Integrated Solution Technique for the Flow/Thermodynamic Equilibrium Equations
Authors: Guehria F. M. , Thompson L. G. , Reynolds A. C. 
Published: December 2007

Abstract
We present a novel highly efficient approach to the discretization and solution of the flow and thermodynamic equations describing multicomponent fluid flow in a porous medium. Comparisons with a standard fully-implicit compositional simulator which utilizes Newton's method indicates that typical execution times for our simulator are five to seven times faster than the fully-implicit model, and that these speeds are achieved with no degradation in accuracy, stability or robustness. In fact, our simulator does not experience convergence difficulties (oscillations) during phase transitions (crossing phase envelopes) that have been routinely observed in other simulators. The remarkable speed achieved by our simulator (with time step sizes controlled by accuracy requirements rather than stability requirements) arises from our radically novel approach to the linearization and solution of the discretized flow equations and thermodynamic equilibrium equations. An incremental gain in efficiency is also achieved by solving the minimum number of equations necessary for accurate flow description at each time step. For an Nc- component system, our model solves a maximum of Nc equations at each gridblock containing two phases (e.g., oil and gas) whereas a conventional fully-implicit simulator solves 2Nc equations (Nc flow mass balance equations and Nc thermodynamic equilibrium constraint equations). This reduction in equations is achieved by rigorously and explicitly incorporating the thermodynamic equilibrium equations in the component mass balance equations at the beginning of each time step. Moreover, the simulator is designed for flexibility, e.g., for describing thermodynamic equilibrium at any "point" in the reservoir where multiple phases coexist, the model uses a Generalized Equation of State1 (EOS) that degenerates to any of five widely used equations of state.
Air Quality Permitting of Onshore Oil and Gas Production Facilities in Santa Barbara County, California
Authors: Sheehan P. E. 
Published: December 2007

ABSTRACT
This paper explains how to quantify the emission of air pollutants from a typical onshore oil and gas production facility in Santa Barbara County, and discusses common problems in the permitting process. The paper describes the sources of emissions, the calculation methods, and the data required to properly do the calculations. It outlines the trigger levels for Best Available Control Technology (BACT), Air Quality Impact Analysis (AQIA), and offsets.
The Evolution of Geothermal Drilling Fluid in the Imperial Valley
Authors: Zilch H. E. , Otto M. J. , Pye D. S. 
Published: December 2007

ABSTRACT
The evolution of geothermal drilling muds used in the Imperial Valley, California began with the first generation Sepiolite muds in 1976. These muds had adequate rheology, but poor fluid loss control and were sensitive to contamination by brine or cement. The second generation muds, 1978 to 1980, utilized Sepiolite with increased amounts of bentonite and lignite to improve fluid loss control. Rheological properties of the second generation fluid were unacceptable and were extremely sensitive to contamination. The third generation muds, have exhibited excellent rheological stability, good filtration control, and are resistant to contamination.
The principal ingredients of the third generation geothermal drilling fluid are bentonite as a viscosifying agent, a low molecular weight copolymer for high temperature deflocculation and rheological stability, a sulfonated lignite and a modified vinyl copolymer for high temperature filtration control. Compared with the sepiolite and lignite based fluids, the new formulation performs better under extreme conditions, such as temperatures in excess of 500°F (260°C), contamination levels of 200,000 ppm CO2-2, soluble calcium over 7000 mg/l, and chlorides over 20,000 mg/l. Even at these high contamination levels, the current mud system maintains rheological stability as well as adequate filtration control.
After extensive laboratory testing of various high temperature fluids, the third generation system was selected as the most promising fluid to be used in California's geothermal drilling operations. Under actual field conditions, the fluid confirmed the performance shown in the laboratory tests, but much lower additive concentrations were required in field muds than in the laboratory tests.
Numerical Studies of Cold Water Injection into Vapor-Dominated Geothermal Systems
Authors: Lai C. H. , Bodvarsson G. S. 
Published: December 2007

ABSTRACT
Recent reservoir pressure and steam flow rate declines at The Geysers geothermal field in California have attracted interest in studies of increased cold water injection into this system. In this paper, numerical studies of such injection into a fractured vapor-dominated reservoir are conducted using a two-dimensional radial, double-porosity model. The results obtained indicate that cold water injection into superheated (low-pressure) zones will greatly enhance the productivities of steam wells. Injection into two-phase zones with significant liquid reserves in the matrix blocks does not appear to aid in steam recovery until most of the original liquid reserves are depleted. Sensitivity studies are conducted over the range of fracture and matrix permeabilities applicable to the Geysers. The sensitivity of the grid size is also conducted, and shows very large grid effects. A fine vertical space discretization near the bottom of the reservoir is necessary to accurately predict the boiling of the injected water.
Reservoir Response to Production: Castle Rock Springs Area, East Geysers, California
Authors: Goyal K. P. , Box W. T. 
Published: December 2007

ABSTRACT
Steam deliverability of the original 20 wells, supplying steam to PG&E Unit 13 power plant, has undergone annual exponential decline rates of 11.5%, 5%, 9%, 28.6% and 22% during 1980–81, 1983–84, 1985–86, 1987–88 and 1988–89 respectively. High decline rates after 1984 were influenced by the regional effects associated with the installation of new capacity in the adjoining areas totalling 383 MW (net) in 1983–84 and 347 MW (net) in 1985–86. Unit 13 production declined harmonically for the first 6.6 years, nearly exponentially for the next year and hyper-bolically to harmonically thereafter. The near exponential decline trend resulted from the combined effect of local and regional pressure drawdowns and an accelerated makeup well drilling program. Analysis of the decline rate versus generating capacity suggests that a sustainable 15% annual exponential decline rate (2 MW per month) is achievable if the capacity is held at about 170 MW (net) in the Unit 13–16 wellfield and 830 MW (net) in The East Geysers. This estimate excludes the positive effects of injection seen in late 1989 and 1990.
Process Enhancement in Horizontal Wells Through the Use of Vertical Drainage Channels and Hydrocarbon Additives
Authors: Nasr T. N. , Kimber K. D. , Vendrinsky D. A. , Jha K. N. 
Published: December 2007

ABSTRACT
In a steam-assisted gravity drainage process, two horizontal wells, superposed 16.4 ft (5 m) apart, are placed near the bottom of the formation. Steam is generally circulated through the wells to establish hot communication paths between them and to initiate gravity drainage. However, this steam circulation phase delays oil production. Results of a research program to investigate two novel methods to eliminate steam circulation and enhance the recovery of bitumen or heavy oil through horizontal wells are described in this paper. In the first procedure, paired horizontal wells were linked transversely with vertical channels to improve liquid drainage, and in the second procedure, naphtha was used as a steam additive to accelerate oil drainage and to Increase ultimate oil recovery. The physical models used in this study were designed according to scaling techniques which insured that gravity drainage was the major mechanism of recovery. The scaling technique also ensured that field bitumen could be used in the model. Geometric similarity was maintained, and time was appropriately scaled.
Six experiments were conducted which indicated that more than 50% of the initial bitumen in place could be recovered in less than four years. Using vertical channels to enhance the drainage of fluids from the injection well to the production well improved oil recovery from paired horizontal wells. When one vertical channel was used for a 65.6 ft (20 m) portion of the horizontal wells, the occurrence of a maximum oil-steam ratio was observed 180 d before that of a baseline experiment and the final recovery increased from 52% to 64%. When two channels were used for a 65.6 ft (20 m) portion of the horizontal wells, the final recovery was lower than that for one channel (56% versus 64%) while the same early production was achieved. Hot fluids bypassed the region between the two horizontal wells, reducing recovery from that region.
The presence of naphtha in the steam further improved the rate of oil production and final recovery. When 5 wt% (0.05 kg/kg) naphtha in steam was used, the final recovery was 82% compared with 64% for a baseline experiment using steam-only injection with one vertical channel. When the naphtha concentration in steam was increased to 10 wt% (0.10 kg/kg), the final recovery was lower than that for the test with 5 wt% (0.05 kg/kg) naphtha (71% versus 82%). A high, non-condensible gas saturation in the steam chamber blanketed the heat transfer interface between the steam and bitumen, reducing heat transfer across the interface.
Oscillatory Injection-Production Schemes for Steamflooding Oil Reservoirs
Authors: Chu C. 
Published: December 2007

ABSTRACT
This report embodies a simulation study on using oscillatory injection-production schemes for steamflooding oil reservoirs. The oscillation in injection being studied included ON-OFF alternation, HIGH-LOW alternation in steam quality and HIGH-LOW alternation in both steam injection rates and steam quality. ON-OFF alternation in production was assumed to be in phase, out of phase or partially in phase with the oscillation in injection. The effects of periods, amplitudes and timing of oscillation on steamflood performance were also studied.
The results showed that simple ON-OFF oscillation, in injection only, injecting steam at the rate of 600 BPD for 6 months, alternating with 6 months of non-injection, can increase the oil production by 6% over injecting steam at the rate of 300 BPD continuously. Furthermore, the oil recoveries at the ends of the first year and the second year are 5.5 and 20.7% of the oil-in-place, respectively, for the oscillating case, much greater than the 2.8 and 14.4%, respectively, obtained without oscillation.
Some Important Considerations in the Simulation of Naturally Fractured Reservoirs
Authors: McDonald A. E. , Beckner B. L. , Chan H. M. , Jones T. A. , Wooten S. O. 
Published: December 2007

ABSTRACT
The effects of rock structural properties on porosity and permeability may be considered as generally well known, being particularly critical when modeling tight sands and limestones. Nevertheless, such effects have been slow to find their way into reservoir simulators. These effects are frequently even more important for fractured horizons where 10-20 porosity per cent changes, and/or several orders of magnitude change in permeability, can be observed under changing reservoir stress conditions. Rocks with weak tensile properties are particularly vulnerable to stress change. These include diatomite, chalks, and overpressured Gulf Coast shales.
Less well known is the dependence of relative permeability on stress. Moreover, the effects of relative permeability and capillary pressure in the fractures themselves need to be accounted for.
Production in naturally fractured reservoirs is limited by the exchange rates of oil and gas between matrix blocks and fractures. Naturally fractured simulators which use the conventional dual porosity formulation fail to resolve gradients in the matrix blocks unless some type of sub-gridding (subdomains) is used. This lack of resolution at the matrix/fracture interface leads to significant errors in production rates when modeling oil recovery from fractured reservoirs.
Treatment Design Changes Improve Production Results for the Codell Formation
Authors: Parker M. A. , Jacobs R. , Yeager R. R. 
Published: December 2007

ABSTRACT
The Codell sandstone in the Denver-Julesburg Basin is a low permeability, clay-rich sandstone. It is bounded by the Ft. Hays limestone member of the Niobrara formation above and shales of the Carlile formation below. The Codell requires stimulation by hydraulic fracturing in order to produce at economic rates; however, some stimulation procedures are not effective.
Analysis of the less successful treatments indicated that inadequate fracture length and conductivity were common problems. Formation properties, gathered in situ, were used in a 3-D fracture design simulator to predict fracture growth in the Codell and bounding formations. Published laboratory data has proven that low proppant conductivities are associated with low proppant concentrations and imply that the use of high concentrations should improve conductivity. In addition, greater initial rates and sustained long-term Codell production support the use of high proppant concentration treatments.
This paper will present a history of treatments and changes which led to more effective stimulation of the Codell formation in the Denver-Julesburg Basin. Comparative production data will show the benefits of this improved treatment design.
Interpretation of In-Situ Pressure and Flow Measurements of the Salado Formation at the Waste Isolation Pilot Plant
Authors: Howarth S. M. , Peterson E. W. , Lagus P. L. , Lie K-H. , Finley S. J. , Nowak E. J. 
Published: December 2007

ABSTRACT
This paper describes preliminary interpretation of in-situ pressure and flow measurements of the Salado Formation at the Waste Isolation Pilot Plant (WIPP). The WIPP facility is located 660 m underground in the Salado, a bedded salt deposit. Shut-in pressure tests were conducted prior to, and subsequent to, the mining of a circular drift in order to evaluate excavation effects on pore pressure, permeability, and host rock heterogeneity. Borehole deformation was measured during these tests and used to correct for changes in the test region volume due to salt creep effects.
Preliminary pre-excavation results indicate that the flow properties of this layered host rock are heterogeneous. Resulting pore pressures range from 1 to 14 MPa and permeabilities range from below measurable to about 1 nanodarcy. Normalized borehole diameter change rates were between -4 and 63 microstrains/day.
Shut-in pressures and borehole diameters in all test boreholes were affected by the excavation of Room Q coincident with the advances of the boring machine. Preliminary results from post-excavation test results show decreased pore pressures compared to pre-excavation values.
Modeling of Poroelastic Effects in Hydraulic Fracturing
Authors: Clifton R. J. , Wang J-J. 
Published: December 2007

ABSTRACT
A computational model is presented which accounts for poroelastic effects, due to fluid migration in the reservoir, during hydraulic fracturing. For massive hydraulic fracturing in a high leakoff formation, the large fluid losses and long injection times cause significant changes in the in-situ stress and the pore pressure of the reservoir. The current model provides a new advanced capability for simulating the evolution of such fractures.
To model the poroelastic effects due to fluid injection, without temperature changes, the reservoir is considered to be a saturated, linear, poroelastic solid. The resulting three-dimensional poroelasticity problem is reduced to a pair of two-dimensional coupled surface-integral equations for the unknown crack opening and leakoff rates [Kurashige and Clifton, 1991]. By introducing commonly used leakoff relations, these equations are uncoupled to obtain an integral equation for crack opening in the poroelastic formation. The difference in pressure required for opening a crack in the poroelastic material versus a purely elastic material is due to the change in the in-situ stress (i.e., backstress) caused by the hydraulic fracturing treatment. These backstresses are evaluated by introducing approximations for the time histories of the crack openings and leakoff which appear in the integrals. These approximations allow the integrations with respect to time to be carried out explicitly in the back-stress calculations. Expressions to account for the poroelastic changes in in-situ stresses and pore pressures are presented. Implementation of this model in a three-dimensional hydraulic fracturing simulator is described. Example simulations are presented and discussed.
A Rapid Sequential Fracturing and Proppant Placement Method
Authors: Passamaneck R. S. 
Published: December 2007

ABSTRACT
This paper describes a research project that was undertaken to develop an enhanced completion method. The criteria for the method was to have a procedure which was capable of perforating, fracturing, and propping in a very short period of time, i.e., on the order of a few seconds at most. A downhole energy generating device was developed which creates gas at high pressure for the Initial fracture. The control of this device is crucial to a successful completion. A means to store potential energy in the vicinity of the zone to be fractured was found in the form of a column of compressed sand-laddened foam. This foam provides from 90 to 95% of the total energy dissipated into the zone to be fractured. A computer code was developed to predict the pressure history of the material within the well bore during the procedure. A second computer code was developed which calculates the fracture volume and weight of sand injected into the fracture. Finally, a test was performed to check the operational procedures, reliability of the ignition sequence, and gas generation capability of the gas generating device.