bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Pressure Buildup Data Following a Short Flow Period
Authors: Raghavan Rajagopal , Reynolds Albert C. , Meng Hai-Zui 
Published: December 2007

Summary
Methods for analyzing buildup data following a short flow period are presented, discussed, and illustrated. A new type curve for uniform-flux and infinite-conductivity vertically fractured wells is presented. By matching buildup data with this new type presented. By matching buildup data with this new type curve, we can determine the dimensionless flowing time before shut-in. A method for converting buildup data to equivalent drawdown data is discussed. This method can be used to combine buildup and drawdown data to obtain a longer band of data for type-curve matching. This method canbe used for constant-rate production, constant-pressure production, and for the case where both pressure and rate production, and for the case where both pressure and rate vary during production.

Introduction
Over the past decade, the use of type-curve matching toanalyze pressure data has gained increasing acceptance. The advantages and dis advantages of type-curve matchingare well recognized and the procedure has become astandard tool to analyze data qualitatively, to identify flow regimes, and, quantitatively, to determine iformation parameters. Virtually all type curves available in the literature examine the pressure response at a flowing well-i.e., only drawdown solutions have been examined. These type curves may be used to analyze shut-in pressure behavior provided that the flowing time before shut-in is provided that the flowing time before shut-in is significantly longer than the maximum shut-in time. This limitation has prevented type-curve analysis ofpressure buildup data following short flow periods. pressure buildup data following short flow periods. The effect of a short flow period on pressure buildup data influenced by either wellbore storage or vertical fractures was presented recently. It was shown that significant errors result if proper care is not taken in analyzing pressure buildup data when the producing timeis short. Procedures to account for the influence of producing time were outlined. producing time were outlined. The objectives of this paper areto present anew correlation that considerably simplifies the use of buildup type curves for vertically-fractured wells givenin Ref. 1, andto suggest a procedure to analyze pressure buildup data by means of drawdown type pressure buildup data by means of drawdown type curves.
The procedures discussed here can be applied to single- or multiwell tests, to data obtained after shortor long flow periods, to constant or variable flow rates, and to virtually all wellbore conditions including data influenced by wellbore storage and skin and fracturesof finite or infinite conductivity.

Theory
The basic pressure buildup equation based on the principle of super position is given by principle of super position is given by (1)
Here, t is flowing time and Delta t is shut-in time. Thesymbols p and t denote dimension less wellbore pressure drop and dimension less time, respectively, and are defined as follows.
JPT
P. 904
Biopolymer Solution Viscosity Stabilization—Polymer Degradation and Antioxidant Use
Authors: Wellington Scott L. 
Published: December 2007

AbstractDilute solutions of polymers used to provide mobility control for EOR often lose viscosity, especially at higher temperatures. This loss of viscosity with time brings into question the feasibility of using polymers as mobility-control agents. A literature study of the many possible reaction mechanisms indicated that oxidation/reduction (redox) reactions involving free radicals probably caused polymer degradation and concomitant viscosity loss.A preliminary search for antioxidants known to retard free-radical reactions located several types and positive synergistic formulations that significantly retarded biopolymer solution viscosity loss during accelerated tests at high temperature. The most effective type formulation found contained (1) a radical transfer agent; (2) a sacrificial, easily oxidizable alcohol; (3) a compatible oxygen scavenger; and (4) sufficient brine concentration. Samples prepared with this technology have not lost viscosity after 1-year storage at 207 °F [97 °C]. A high-surface-area effect (so-called "wall effect"), known to retard radical propagation, was also found to operate in the presence of sandpacks; this should be beneficial in porous media. The variables and beneficial antioxidant formulations identified in this study allow tentative conclusions and recommendations regarding biopolymer mixing and handling procedures prior to injection.
The Effects of Mechanical Degradation and Viscoelastic Behavior on Injectivity of Polyacrylamide Solutions
Authors: Seright R. S. 
Published: December 2007

AbstractResults of recent experiments that clarify the effects of mechanical degradation and viscoelastic behavior on the flow of partially hydrolyzed polyacrylamide solutions through porous media are presented. From these results, a simple model that may be used to predict injectivity of polyacrylamide solutions is developed.Injection pressures for linear corefloods are shown to be separable into two components: (1) an initial pressure drop associated with the entrance of polymer into the sandstone and (2) a constant pressure gradient throughout the remainder of the core. Entrance pressure drop is zero until the polymer solution flux increases to the rate where mechanical degradation takes place. Thereafter, entrance pressure drop and the degree of polymer mechanical degradation increase with increasing flux. In addition, polymer solutions that undergo a large entrance pressure drop and a high degree of mechanical degradation when first injected into a core show no entrance pressure drop and no further degradation after reinjection into the same core at the same flux. These observations suggest that the entrance pressure drop is associated closely with the process of polymer mechanical degradation.A new correlation is developed that may be used to determine entrance pressure drop and the level of mechanical degradation directly as a function of sand-face flux, permeability, and porosity. This correlation is more convenient to apply and less dependent on flow geometry than previous correlations.Based on these observations, a model is developed that may be used to estimate injectivity of polyacrylamide solutions in linear or radial flow geometries. This model takes into account the entrance pressure drop and the dilatant nature of the polymer near the wellbore. Predictions made with this model are compared with experimental results.
Polymer Flooding in North Sea Reservoirs
Authors: Davison Paul , Mentzer Eric 
Published: December 2007

Abstract
The use of polymer solutions to enhance oil-displacement efficiency by seawater injection in North Sea oil reservoirs has been investigated. We have evaluated over 140 polymers for viscosity retention and porous media flow performance under high temperature (90°C), high salinity, and high pressure. Scleroglucan polymers give the best performance in our tests. Polyacrylamides (PAAm's) are particularly unsuitable for mobility control. Using polymers to enhance seawater injection and waterflooding processes is not practical in North Sea reservoirs, but selective injection may improve local sweep efficiencies.
The Influence of Vertical Fractures Intercepting Active and Observation Wells on Interference Tests
Authors: Mousli Naelah A. , Raghavan Rajagopal , Cinco-Ley Heber , Samaniego-V. Fernando 
Published: December 2007

Abstract
This paper reviews pressure behavior at an observation well intercepted by a vertical fracture. The active well was assumed either unfractured or intercepted by a fracture parallel to the fracture at the observation well. We show that a vertical fracture at the observation well has a significant influence on the pressure response at that well, and therefore wellbore conditions at the observation well must be considered. New type curves presented can be used to determine the compass orientation of the fracture plane at the observation well.
Conditions are delineated under which the fracture at the observation well may influence an interference test. This information should be useful in designing and analyzing tests. The pressure response curve at the observation well has no characteristic features that will reveal the existence of a fracture. The existence of the fracture would have to be known a priori or from independent measurements such as single-well tests.
The Topology of Phase Boundaries for Oil/Brine/Surfactant Systems and Its Relationship to Oil Recovery
Authors: Bourrel M. , Chambu C. , Schechter R. S. , Wade W. H. 
Published: December 2007

Abstract
Surfactant/oil/water phase diagrams have become the most important screening tool used to select microemulsion systems for enhanced oil recovery. The number of phases coexisting at a given salinity, the extent of the single-phase region, and the position of the phase boundaries all have relevance with respect to oil displacement efficiency.
It is shown that the phase diagrams can be made to take on different configurations depending on the alcohol cosurfactant, the salinity, the impurities present in the surfactant, and the dispersity of the surfactant mixture.
Besides the importance of the phase boundary shape, this study provides further insight into factors determining the height of the binodal surface on the pseudoternary phase diagram. Results show the effect of salinity as well as the surfactant, alcohol, and hydrocarbon types on the height of the binodal surface. It is shown that salinity is the main factor; other parameters have little or no influence once a surfactant has been selected.
Finally the microemulsion viscosity is shown to be related to the proximity of the formulation to phase boundaries. Extensive data for one system are presented.
Acidizing Sandstone Formations With Fluoboric Acid
Authors: Kunze Kenneth R. , Shaughnessy Chris M. 
Published: December 2007

Summary
The continuing search for an effective deep-penetrating sandstone acidizing system recently has focused on fluoboric acid (HBF4). Because this acid first must hydrolyze in water to produce HF, it was believed that deeper radial penetration of live acid could be achieved during matrix acidizing operations. However, a thorough experimental study has shown that typical formation temperatures will cause fluoboric acid to spend at a rapid rate similar to that of conventional hydrofluoric acid (HF), thereby severely limiting its usefulness in most sandstone formations. Furthermore, the same silica reprecipitation potential associated with HF acidizing is also inherent in the HBF4 system.
Physics of Oil Entrapment in Water-Wet Rock
Authors: Mohanty K. K. , Davis H. T. , Scriven L. E. 
Published: December 2007

Summary
Displacement of oil from an initially oil-filled porous rock by water consists of advancement of menisci and rupture of oil connections. In displacements controlled by capillarity, which are typical of oil reservoir floods, these pore-level events are governed by the local pore geometry, pore topology, and fluid properties, but the pressure field initiates these pore-level events and integrates them with the externally imposed Darcy flow.
This paper reports the physics of the pore-level events and their integration on a computationally simple model of rock: a square network of pores. The novelty of the approach lies in keeping track of the evolution of the displacement front and in constructing an approximation of the entire pressure field that carries the information essential for predicting the evolution.
The result gives insight into the state of the residual oil saturation and its dependence on pore geometry and the capillary number, Nca, of displacement. As the capillary number increases, the residual oil saturation decreases and the residual oil blobs tend to be smaller. As the pore size distribution becomes wider, the decrease of residual oil saturation with capillary number becomes smoother.
Steady-State Measurements of Relative Permeability for Polymer/Oil Systems
Authors: Schneider F. N. , Owens W. W. 
Published: December 2007

Abstract
Means for increasing tertiary oil recoveries from previously waterflooded viscous oil reservoirs are receiving added attention today as a result of industrywide efforts to improve U.S. oil producing rates and reserves. Injection of a bank of polymer solution that precedes injection of a miscible slug (e.g., a micellar fluid) can reduce reservoir permeability contrasts and result in improvement of the sweep efficiency of the process. To evaluate the potential magnitude of improved recovery and economics of prior polymer slug injection, there is a need for basic polymer/oil relative permeability data for use in performance evaluation calculations. Such relative permeability data were measured by steady-state procedures on a suite of 18 outcrop and formation core samples ranging in permeability from about 50 to 1,200 md. Six different Polyacrylamide polymers were tested, and resistance and residual resistance data were obtained on each. Data were obtained in both oil-wet and water-wet systems. The observation in these studies was that the presence of polymers in the water phase had a significant and consistent effect, lowering water relative permeability over the entire water saturation range. In many of the tests, the presence of flowing polymer or its residual effect during subsequent brine flow had no effect on oil relative permeability. In several tests, polymer contact actually improved oil mobility through increases in oil relative permeability at all levels of oil saturation. Permeability level and polymer type produced no clear-cut differences in flow behavior. The obvious differences in core wettability resulted in widely varying relative permeability characteristics, but again the effect of polymer contact was about the same, qualitatively, as obtained on the water-wet cores.
Unique Enhanced Oil and Gas Recovery for Very High-Pressure Wilcox Sands Uses Cryogenic Nitrogen and Methane Mixture
Authors: Eckles Wesley W. , Prihoda Clarence , Holden W.W. 
Published: December 2007

Summary
Primary recovery is low for the volatile oil and retrograde condensate reservoirs in the hot, high-pressured, multilayered Wilcox sands in the Fordoche field, Point Coupee Parish, LA. Recovery from oil reservoirs by depletion is predicted by numerous model studies to be 26 to 36% of the OOIP. Condensate recovery by depletion is predicted to be 19% of the original condensate in place and 25% of original separator gas in place. The injection of dry natural gas at high pressures will result in a miscible displacement of reservoir fluids. The immiscible displacement of reservoir fluids. The injection of a mixture of nitrogen and dry gas is predicted to be as effective as injecting dry natural gas. Model studies of gas injection in volatile oil reservoirs predict recoveries from 47 to 54% of the OOIP, and in the retrograde condensate reservoir recoveries are predicted to be 30 and 46% of the original condensate and gas in place. Oil recovery studies at 6,955 psig indicate that gas injection will displace 89% at breakthrough and 93% at blowdown at 100% sweep efficiency. A well stimulation program has been developed that results in a 2.5-fold increase in production rates.

Introduction
The Fordoche field was discovered by Sun Oil Co. in 1966. The location is shown in Fig. 1. The field was developed fully on 160-acre well spacing by 1970. A total of 36 wells was drilled during the short 4-year development period. Well depths ranged from 11,800 to 16,500 ft (See Fig. 2, a typical log for the Fordoche field.) Seven reservoirs encountered between depths of 11,300 to 13,900 ft had initial bottomhole pressures (BHP's) ranging from 8,372 to 11,018 psig and bottomhole temperatures (BHT's) ranging from 226 to 278°F. The Sparta sands are undersaturated oil reservoirs. The Wilcox 4 and 5 (W-4 and W-5) sands are gas-condensate reservoirs. The W-8, W-12, and W-15 sands are undersaturated volatile oil reservoirs. All of the Wilcox reservoirs experienced rapid rates of reservoir pressure depletion. Productivity of all wells declined severely.
After evaluating water injection and gas injection programs, high-pressure gas injection was selected for the two major oil reservoirs, W-8A and W-12A, and for the largest retrograde reservoir, W-5A. (See Figs. 3, 4, and 5).
A very high-pressure miscible gas injection project was instituted to maintain pressure and well productivity and to enhance ultimate recovery. Initially, extraneous gas was purchased for makeup and injected with the processed natural gas produced in the field. Because of the increasing cost of natural gas and the restricted oil price of $5.35 per barrel, economics dictated that the project be changed to a partial pressure maintenance program with a lower ultimate recovery or find a substitute for natural as used for makeup.
"Silicalock" - A Novel Sand-Control Process for Gas Wells
Authors: Davies David R. , Zwolle Simon , Meijs Frans H. 
Published: December 2007

Summary
A novel sand-consolidation technique especially suited for the prevention of sand influx in gas wells is described. This technique-"Silicalock"-has the advantage of being a single-chemical one-phase dynamic treatment that can be carried out through tubing and that leads to reduced chances of productivity impairment. The results of three successful field tests also are described.

Introduction
The importance of natural gas as an essential and clean source of energy has increased considerably in recent years. Much of this gas is produced from loosely consolidated sandstone reservoir that require some form of sand control. Experience in both field and laboratory has shown that the probability of sand influx increases as a reservoir is depleted and pore pressure decreases. Production facilities may be, designed to cope safely with the production of small amounts of sand. However, sand production over a long time is generally not acceptable since it often leads to serious erosion problems. Furthermore, some of the produced sand will normally remain in the wellbore, which may result in a sand fill that adversely affects the well's productivity. The standard forms of sand control, primarily developed for oil wells, also may be applied to gas wells. These include(1) beaning back production, (2) mechanical methods such as wire-wrapped screens with and without gravel packs, and (3) consolidation processes in which the sand grains are "glued" together. However, none of these methods makes allowance for the special conditions found in gas wells, and they are therefore not optimal. The Shell group of companies has been exploiting several large gas fields during the past decade, including the giant Groningen field [operated by the Nederlandse Aardolie Mij. (NAM)] where about 280 wells can produce up to 480 × 10 std m /d during peak winter production periods. A view to possible future sand problems justified the star, of development of a sand control process especially geared to the conditions prevailing in gas wells. This has resulted in the novel chemical technique "silicalock" described in this paper. The process is based on the following reaction.
SiCl4 + - 2H20- silica cement +4 HCl.
The water is supplied by the connate water naturally adhering to the sand grains. The process differs from previous sand consolidation processes involving silicon tetrachloride in that it operates from the gas phase. The "silicalock" technique consists in vaporizing liquid silicon tetrachloride into a stream of high-pressure nitrogen gas. The mixture is injected into the well, preferably through coiled tubing. Immobile water present in the near-wellbore region is converted into silica cement, which cements the grains together, thus preventing any (further) influx of sand into the well.
JPT
P. 2087^
Field Experience Utilizing High-Density Brines as Completion Fluids
Authors: Spies R.J. , Himmatramka A.K. , Smith J.R. , Thomas D.C. 
Published: December 2007

Summary
This paper presents the results of 2- years experience using high-density brines as completion fluids in fields offshore Texas. This experience has resulted in a number of improvements in field methods of handling and using these fluids in making gravel-packed completions in abnormally pressured wells. Because the required fluid densities have been in the range of 15.0 to 15.6 Ibm/gal (1797 to 1869 kg/m ) and the fluids have cost several hundred dollars per barrel, the cost of lost or contaminated fluid has been a significant factor in carrying out these completions. We have developed our current completion methods in an effort to minimize fluid costs, maintain well control, maximize productivity, and minimize rig time per completion. The methods developed include those for perforation cleaning, gravel packing, solids removal, density control, control of fluid losses, and prevention of crystallization. The results of these methods generally have been successful in controlling completion costs and apparently are successful in providing good sand control and adequate flow efficiencies on the basis of initial test results for about two-thirds of the wells.

Introduction
Amoco Production Co., as operator for a group consisting of Mobil Oil Corp., Union Oil Co. of California, and Amoco, acquired three adjoining Outer Continental Shelf leases in the May 1974 federal offshore lease sale in what would become the High Island Block A-537 field, The field has been the primary location where we have used high-density brines. This paper describes the basis for using heavy brines in these completions, the plans developed for the completions, our experience in performing them, the resultant evolution of our procedures, and the achieved well productivities, which have confirmed the advantage of using a solids-free completion fluid.
The field is located approximately 85 miles (137 km) south-southeast of Galveston, TX, in water depths of 190 to 200 ft (58 to 61 m) in the Gulf of Mexico. Exploratory drilling began in 1974, and a total of five exploratory wells were drilled during 1974–75. The first exploratory well drilled in the field, OCSG-2698 Well No. 1, encountered hydrocarbons in Pleistocene sands while being drilled with 16.5 lbm/gal (1977 kg/m3) mud. The well was cased, and a drillstem test (DST) was made in a 10-ft (3.05-m) perforated interval. The well flowed at rates of 450 to 720 B/D (71.5 to 114 m3/d) oil. The shut-in bottomhole pressure (BHP) was 5.243 psig (36.1 MPa) [a 13.7-lbm/gal (1641 -kg/m3) equivalent] at 7,352 ft (2241 m) TVD. Following this DST, sand had to be washed from the well beginning at a depth 80 ft (24.4 m) above the perforated interval, indicating that sand control would be necessary in wells completed in this field.
JPT
P. 881^