bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gravel Pack and Formation Sandstone Dissolution During Steam Injection
Authors: Reed M.G. 
Published: December 2007

Laboratory and field flow studies show gravel-pack sands and formation sandstones may be dissolved rapidly in steam generator effluents. Dissolution rates are affected markedly by changes in solution pH and temperature. Photographs and scanning electron micrographs show changes in rock morphology caused by silica dissolution.

Introduction
Steam stimulation and steamflooding of oil reservoirs have been used for many years to help produce viscous oil more effectively. Recently it was shown that steam drive also was applied successfully in a relatively low-viscosity oil reservoir. This success combined with the need to increase domestic oil production may lead to expanded use of steam injection in the oil field.In cyclic steam stimulation it is common to inject perhaps 3000 m3 (18,870 bbl) of 80% quality steam at about 260 degrees C (500 degrees F) on each of several stimulation cycles. Thus, a few thousand cubic meters of liquid-phase water (20% of total) may be injected into a well during several steam stimulation cycles. In the case of a steam-drive injection well, tens of thousands of cubic meters of liquid are injected into the formation over the life of a project. If the formation rock and any gravel pack that may be in the well have any significant solubility in the flowing fluid, a rather large amount of rock could be dissolved. For example, if rock solubility is only 100 ppm (100 mg/L), 10 000 m3 of injected fluid will dissolve 1000 kg (2,200 lbm) of rock. If this dissolution occurs rapidly, a gravel pack would be short-lived. In the case of a large loss of formation rock from the immediate well area, formation caving and perhaps even casing or liner collapse could result.Quartz and other siliceous minerals have very low solubilities at room temperature, but at elevated temperatures solubilities increase rather sharply (Fig. 1) as reported by Krauskopf. Thus, there is ample Si solubility at normal steam injection temperatures to cause concern, although the actual rate of dissolution is not known. However, the rate is as important as solubility because it determines if severe dissolution occurs in or immediately adjacent to the injection wellbore or if it occurs less intensively over a larger radius.Solution pH also is an important factor influencing the extent and rate of Si dissolution. When HCO3 ions in steam generator feedwater decompose to CO2 and OH ions, the CO2 partitions to the vapor phase and the OH ions partition to the liquid phase. This causes the pH of the generator liquid effluent to increase sharply, the extent of which is dependent on the HCO3 content of the feedwater. Some of the OH ions react with remaining HCO3 ions to form CO3 ions, which also are quite alkaline. Measurements on samples of liquid effluent collected from field generators show that about one-third to one-half of the alkalinity is from CO3 ions and the rest is from OH ions.
JPT
P. 941＾
Application of Large Computers to Reservoir Engineering Problems
Authors: McCarty D.G. , Peaceman D.W. 
Published: December 2007

Abstract
The primary applications of automatic computing equipment to the field of engineering are (1)the development of engineering information more economically and (2) the production of improved engineering analyses. While experience has demonstrated that both large and small computers are useful in the first application, it presently appears that the large computer will be required to investigate multiphase flow and to predict the flow behavior of oil and gas reservoirs considering two- and three-space dimensions.
Some of the mathematical difficulties which arise in connection with the equations describing flow of fluids in oil and gas reservoirs are briefly reviewed, and some of the recent developments in the application of numerical techniques to reservoir engineering problems are discussed. The general computational requirements for typical problems of this type are included, and the specific time requirements for effective application of a few of the newer analyses to actual reservoir cases using both large and small computers are compared.

Introduction
The advantages of using high-speed computing equipment in engineering work fall generally into two categories. First, it is possible to conserve engineering manpower in that the inherent high computing rate of these devices can be directed so as to perform the engineering calculation work of many men. The second and potentially more significant advantage afforded by effective application of the high-speed computer is the ability to produce information which otherwise would not be available to the engineer. This is usually made possible by employing new or improved methods of analysis.
New and improved methods of engineering analysis are beginning to evolve from the aggressive research programs on the application of numerical methods which various industrial research groups initiated five to 10 years ago. Techniques have been developed for studying problems in reservoir mechanics, such as unsteady gas flow and flow of single-phase fluids in two- and three-space dimensions, and improvements have been made in techniques for studying multiphase flow.
Maximizing Yibal's Remaining Value
Authors: Mijnssen F. C. J. , Rayes D. G. , Ferguson I. , Al Abri S. M. , Mueller G. F. , Razali P. H. M. A. , Nieuwenhuijs R. , Henderson G. H. 
Published: December 2007

SummaryReserves in Yibal traditionally have been targeted by infill drilling, initially with vertical wells and, since 1994, with horizontal wells. Since 1999, new well results have been disappointing, and drilling was suspended in early 2001. An integrated field review was kicked off to design the next era of Yibal development to maximize the remaining value.The review began with an integrated well and production review. This review concluded that horizontal wells drilled in 1994 and 1995 produced significantly more oil than the original vertical wells. However, later horizontal wells produced similar amounts of oil as the vertical wells, but at much higher water cut.Based on the well and production review, 13 development opportunities have been identified. A focus area was identified within the field to test these development opportunities. A comprehensive data-gathering campaign of production and saturation logging has been completed in addition to detailed integrated modeling. Subsequently, two infill wells were drilled targeting bypassed oil pockets. These wells confirmed the data-gathering and modeling results and highlighted the further development potential in the Yibal field.
Interfacial Effects in Gas-Condensate Recovery and Gas-Injection Processes
Authors: Meleán Y. , Bureau N. , Broseta D. 
Published: December 2007

SummaryThis paper evaluates the behavior of the dimensionless numbers that gauge the gas/oil interfacial tension (IFT) with respect to the other forces (viscous and buoyancy forces) involved in two-phase flow through porous media. These numbers, referred to respectively as the capillary and Bond numbers, diverge on approach to gas/oil complete miscibility, meaning that viscous and buoyancy forces become dominant over capillary forces. The divergence behaves as a power of the distance to complete miscibility as quantified, for instance, by the difference in densities between the oil and gas phases. The exponents of these power laws are "universal," whereas the prefactors vary between gas/oil systems. This allows the classification of the most common injection gases with respect to their efficiency in reducing the gas/oil IFT. This efficiency increases with the miscibility of the injected gas in the oil: supercritical CO2 is more effective in reducing IFT than off-critical CO2 or CH4, which themselves are more effective than N2.A simple procedure is then introduced to determine the wetting (or spreading) behavior of oil on a porous substrate covered with water, as often occurs in practice. The only inputs required are the composition and densities of the three coexisting phases: water, oil, and gas. When they are not measured, these quantities can be calculated by means of an appropriate equation of state. CO2 turns out to be the most effective for promoting the spreading of the oil on water, followed by CH4 and then by N2.
Predicting Permeability From Well Logs in Carbonates With a Link to Geology for Interwell Permeability Mapping
Authors: Jennings James W. , Lucia F. Jerry 
Published: December 2007

Summary
This paper presents a model to estimate permeability from well logs in carbonate reservoirs. The model relates permeability to interparticle porosity, makes special accommodation for separatevug porosity, and includes a rock-fabric classification scheme with an important dual petrophysical-geological significance. The dual significance of the rock-fabric classification provides an important link to geological models for use in distributing permeabilities between wells. Porosity and permeability are highly variable and are difficult to predict spatially in most carbonate reservoirs, but rock-fabric changes tend to be organized systematically within a sequence stratigraphic framework.
Theory and Analysis of Injectivity Tests on Horizontal Wells
Authors: Peres Alvaro M. M. , Reynolds Albert C. 
Published: December 2007

SummaryThis work presents information on the pressure behavior at a horizontal water-injection well completed in an oil reservoir. We show that, quite remarkably, the pressure and pressure derivative behavior is similar to that of the single-phase solution calculated with oil properties evaluated at initial water saturation. This behavior is quite different from the injectivity solution for a vertical well where, except at early times, the injectivity solution is similar to the single-phase solution based on water properties. It is shown that flow regimes can be identified with the standard log-log diagnostic plots. The Thompson-Reynolds steady-state theory for multiphase-flow well testing is applied to derive a simple accurate approximate analytical solution for the wellbore pressure during injection for both the horizontal and vertical well cases. The horizontal well solution is completely new. Unlike the previous solutions for the vertical well case, we have incorporated a skin zone based on Hawkins' formula. The analytical solution, verified by reservoir simulation results using hybrid grids and local grid refinement, shows that the movement of injected water in a damaged zone has a strong and distinctive effect on both the pressure and pressure-derivative behavior at early times. Based on the analytical solution, we propose procedures for analyzing pressure data from injectivity tests.
Evaluation of Multiphase Flow Rate Models for Chokes Under Subcritical Oil/Gas/Water Flow Conditions
Authors: Schüller R. B. , Solbakken T. , Selmer-Olsen S. 
Published: December 2007

SummaryKnowing the mass flow rate is important in relation to production control in the oil and gas industry. If the change in pressure and temperature across a choke can be correlated with the mass flow rate, the actuator position, and the properties of the well stream, this may constitute a mass flow rate meter that is both simple and inexpensive compared to other designs. However, knowledge of the predictive ability and accuracy of available mass flow rate models is required to qualify such a solution. Predictions from several mass flow rate models are compared with data from a crude oil/natural gas/water system at pressures varying from 8 to 16 bara. The fluids used were recombined oil from the Njord field in the North Sea, natural gas from the Kaarstoe terminal in Norway, and water with added salts to give typical produced-water properties. Two different choke geometries (orifice and cage type) were tested for three different opening areas. The experimental results are compared with eight mass flow rate models for multiphase flow through chokes. These are the two Hydro models originally developed by Selmer-Olsen, the Sachdeva et al. model, the Perkins' model, and four two-phase multiplier models—the Morris, the Chisholm, the Simpson, and the homogeneous equilibrium model (HEM), respectively. For the orifice-type geometry, the Hydro short model predicted the results most accurately. For the cage-type geometry, the Hydro long model, which includes losses in the choke geometry, predicted the results most accurately. A modification to the slip model improves the results of the Hydro models, predicting all the 367 test points with a standard deviation of 7.8%. The average error of absolute values was 5.8%.
Occurrence, Prediction, and Prevention of Zinc Sulfide Scale Within Gulf Coast and North Sea High-Temperature and High-Salinity Fields
Authors: Collins I. R. , Jordan M. M. 
Published: December 2007

Summary
In oil and gas production operations, precipitation of mineral scales causes many problems, such as formation damage, production losses, increased workovers in both producers and injectors, poor injection-water quality, and equipment failures caused by underdeposit corrosion. The most common mineral scales are sulfate- and carbonate-based minerals. However, scale problems are not limited to these minerals, and there recently have been reports of unusual scale types, such as zinc and lead sulfide. This paper focuses on zinc sulfide scale that has been found in several fields along the Gulf Coast of the U.S.A. and in fields within the North Sea Basin. Scale deposition has caused significant pressure and rate reductions in high-temperature and high-rate gas, condensate, and black oil wells. After acid washes to remove zinc sulfide scale (and other acid-soluble solids), production rates and flowing tubing pressures returned to previous levels, but new scale deposits formed in many wells and retreatments were required. Topside process equipment, most noticeably low-pressure separators and hydrocyclones, were observed to suffer reductions in performance owing to zinc sulfide scale deposition. In addition, there are significant risks associated with acid treatments in high-temperature, high-pressure (HT/HP) gas wells in corrosivity of the acid at high temperatures (general corrosion, sulfide stress cracking, and chloride stress cracking) and in safety (hydrogen sulfide generation by acid dissolution of zinc sulfide plus high-pressure pumping). One possible method for preventing production declines and reducing the need for HT/HP acid jobs is to use scale inhibitors or chelating agents to prevent the formation of zinc sulfide scale. The relative effectiveness of eight scale-inhibitor chemistries and two chelating agents in preventing formation of zinc sulfide scale has been determined. The required scale-inhibitor concentrations are significantly higher than those needed for common sulfate and carbonate scales. For chelating agents, it is possible to prevent the formation of zinc sulfide scale when the required concentrations are proportional to the zinc ion concentration in the scaling brine. This paper outlines the testing methods used for chemical screening and prediction so that assessment of the potential problem within fields can be assessed during appraisal, before production commences, making a method of managing the risk available.
Statistical Assessment and Management of Uncertainty in the Number of Electrical Submersible Pump Failures in a Field
Authors: Sawaryn S. J. , Ziegel E. 
Published: December 2007

Summary
Successfully managing a population of electric submersible pumps (ESPs) requires an accurate estimate of the expected number of failures as a function of time plus a determination of the associated uncertainty. Knowledge of the uncertainty is required for an effective risk assessment to be made of workover strategies and the impact of these on production economics. Though the oilfield literature contains discussions of the models and methods for estimating the expected number of ESP failures, little discussion has been presented on the confidence of such estimates.
This paper contains details of how the choice of model, parameter estimates, and variations in a well's economic criteria affect the confidence limits. It shows that the uncertainties inherent in continuously replacing ESPs and estimating their run lives may make the estimates of the number of failures across an entire field considerably uncertain. This effect is particularly pronounced during the first few years after field startup. Under these circumstances, the distribution of the number of failures is skewed, and a 60% difference between the estimated and recorded number of failures is possible. Statistical models also enable differentiation in performance between manufacturers and technologies. It is shown that even large differences in the measured run life may not be conclusive evidence of technical or manufacturing superiority. Based on these results, actions are suggested to reduce the uncertainty and improve the management of a field.
Predicting Brine Mixing Deep Within the Reservoir and Its Impact on Scale Control in Marginal and Deepwater Developments
Authors: Mackay E. J. , Jordan M. M. , Torabi F. 
Published: December 2007

SummarySulphate scale deposition is a common problem in hydrocarbon reservoirs in which injection seawater that is rich in sulphate mixes with formation brines that are rich in barium, strontium, and calcium. Deposition of these scales can cause significant production impairment if it occurs within zones near the production wellbores. To control scale deposition in the near-wellbore region of a reservoir, scale squeeze treatments are commonly deployed. In cases in which scale severity is very high, removal of sulphate ions from the injection water is an alternative scale-control strategy. Both these mitigation methods have associated capital (CAPEX) (e.g., desulphation plant) and operating expenditures (OPEX) (e.g., scale squeeze treatments).To assess the severity of the problem in new fields, thermodynamic calculations typically are performed to calculate the mass of scale that will form. Until recently, little work has been carried out to identify the location of scale formation within the reservoir. In this paper, field data and flow simulations from three North Sea fields are presented to show that scale formation can, in fact, occur deep within the reservoir and can have a negligible negative impact on oil production in the near-wellbore region.Evidence is presented from these North Sea fields that shows the evolution of the brine chemistry as seawater breakthrough occurs and as squeeze treatments are applied. The evidence from the produced brine chemistry is linked to flow calculations for these fields to show that in some systems scale is depositing deep within the reservoir, reducing the potential for damage in the near-production wellbore region. The extent and impact of the deposition varies throughout the reservoir and can be quantified. Modeling brine mixing and stripping of the scaling ions before the fluids reach the production wellbore has a significant impact on the economic assessment of marginal fields and deepwater developments. In such fields, the technical challenge and cost (CAPEX/OPEX) of scale control might make development uneconomical. This paper outlines the data requirements and methodology used to allow such an assessment to be made.
A New Comprehensive, Mechanistic Model for Underbalanced Drilling Improves Wellbore Pressure Predictions
Authors: Pérez-Téllez C. , Smith J. R. , Edwards J. K. 
Published: December 2007

SummaryA new comprehensive, mechanistic model that allows more precise predictions of wellbore pressure and two-phase flow parameters for underbalanced drilling (UBD) is proposed. The model incorporates the effects of fluid properties and pipe sizes and, thus, is largely free of the limitations of empirically based correlations.The model is validated against actual UBD field data and fullscale experiments in which the gas and liquid injection flow rates as well as drilling fluid properties were similar to those used in common UBD operations. Additionally, a comparison against two different commercial, empirically based UBD simulators shows better performance with the mechanistic model.
On the Calibration of Design Collapse Strengths for Quenched and Tempered Pipe
Authors: Adams A. J. , Moore P. W. , Payne M. L. 
Published: December 2007

Summary
The joint API/ISO Work Group 2b under Steering Committee 5 (SC5) for tubular goods is currently rewriting API Bull. 5C3/ISO 10400 for casing and tubing performance property equations. This paper describes the proposed new treatment for collapse of quenched and tempered (Q&T) pipe.
The work is still in progress, and the final text has yet to be agreed upon, but the present results are considered reasonably mature and have been circulated as a committee draft for international comment.
Committee work has shown that the current (sixth edition) rating equations give highly variable risk over the Do/t range for downhole well tubulars, whereas the proposed new equations give nearly uniform risk. Different ratings are proposed for cold- and hot-straightened pipe. Overall, they result in minor cost savings with respect to the sixth edition of API Bull. 5C3 collapse strengths.
The Wilson Creek Field, Rio Blanco County, Colorado
Authors: Ladd J.B. 
Published: December 2007

Abstract
The Wilson Creek field is situated in mountainous terrain of Rio Blanco County, Colo. It was discovered in early 1938 and produces from both the Morrison and Sundance sands of Jurassic age. The underlying Sundance reservoir is fully developed with 18 wells; no dry holes have been drilled. The overlying Morrison reservoir of greater areal extent is almost completely developed with 21 producing wells and three dry holes around the periphery of the field; in addition, all or most of the 18 inside Sundance wells will eventually serve to exploit the central portion of the Morrison reservoir.
The Morrison reservoir was moderately undersaturated with an initial average pressure of 2,180 psig and a bubble point pressure of about 1,100 psig; a partial water drive is in effect. A top structure gas injection program was started early in the life of the pool, resulting in a dampened pressure decline rate and increased oil recovery.
The Sundance reservoir is greatly undersaturated and exhibits a prolific water drive. Individual well fluid capacities are generally high and edgewater-type encroachment is evident throughout all producing levels. A down-flank gas injection project has recently been instigated.
The field is completely electrified and power is generated in a field plant. The operators own and maintain an 18-mile pipeline through which over 7,000 BOPD may be shipped by gravity flow. Major operational problems are related to extended winter periods of extreme cold and deep snow, rough terrain, paraffin accumulations, water disposal, and high water:oil and gas:oil ratio control.

Introduction
The Wilson Creek field is located on the northern edge of Rio Blanco County, Colo., about 25 miles southwest of Craig, the only railhead in the area, and 10 miles north of Meeker. For geographical orientation see Fig. 1. The local terrain is mountainous, being in the more rugged portion of the regional Danforth Hills anticlinical trend. It is readily accessible year-around via well-maintained county roads connecting the local federal and state highway system.