bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory-Based Evaluation of Gas Well Deliverability Loss Caused by Water Blocking
Authors: Kamath Jairam , Laroche Catherine 
Published: December 2007

Summary
Water blocking caused by invasion of completion fluids has been suspected to reduce gas well deliverability.1–5 However, this effect has not been quantified. We report results of a laboratory program to measure the water-blocking effect in core samples from a gas field. These data were mapped to a wellbore model to make deliverability predictions.
The laboratory data consist of gas flow rate as a function of injected gas pore volume for various liquids (brine, methanol, toluene, isopropyl alcohol, and brine-methanol mixtures) at two saturation states (fully saturated with liquid, and containing liquid and trapped gas). We injected over 10,000 PV of gas in each test to mimic near-wellbore conditions. The data showed that the liquid displacement regime was followed by a mass transfer regime.
The wellbore model had a time varying skin to account for the cleanup of the fluid invaded ("water-blocked") region. Cleanup occurs as gas flows past this high liquid-saturated region and removes liquid by displacement and mass transfer. We used the laboratory data to relate the reduced permeability of this region to pore volumes of gas throughput.
We find that any loss in gas well deliverability recovers in two phases. The first phase corresponds to fluid displacement ("flowback period") and lasts for a few days at most. The second phase is slower and can last several months. Here, evaporation causes the deliverability to slowly increase. It is in this regime that adding volatile fluids, such as methanol, to the completion brines has advantages.
Transient Rate Decline Analysis for Wells Produced at Constant Pressure
Authors: Ehlig-Economides C. A. , Ramey H. J. 
Published: December 2007

Abstract
Although constant-rate production is assumed in the development of conventional well test analysis methods, constant-pressure production conditions are not uncommon. Conditions under which constant-pressure flow is maintained at a well include production into a constant-pressure separator or pipeline, steam production into a backpressured turbine, or open flow to the atmosphere.
To perform conventional well test analysis on such wells, one common procedure is to flow the well at a constant rate for several days before performing the test. This procedure is not always effective, and often the delay could be avoided by performing transient rate tests instead. Practical methods for transient rate analysis of wells produced at constant pressure are presented in this paper. The most important test is the analysis of the rate response to a step change in producing pressure. This test allows type-curve analysis of the transient rate response without the complication of wellbore storage effects. Reservoir permeability, porosity, and the wellbore skin factor can be determined from the type-curve match. The reservoir limit test is also important. Exponential rate decline can be analyzed to determine the drainage area of a well and the shape factor.
The effect of the pressure drop in the wellbore due to flowing friction is investigated. Constant wellhead-pressure flow causes a variable pressure at the sandface because the pressure drop from flowing friction is dependent on the transient rate. Finally, for testing of new wells, the effect of a limited initial flow rate due to critical flow phenomena is examined.
Gas Cycling and the Development of Miscibility in Condensate Reservoirs
Authors: Jessen K. , Orr F. M. 
Published: December 2007

SummaryThis paper presents a detailed analysis of the development of miscibility during gas cycling in condensate displacements and the formation of condensate banks at the leading edge of the displacement front.Dispersion-free, analytical 1D calculations are presented for enhanced condensate recovery by gas injection. The analytical approach allows investigation of the possible formation of condensate banks (often at saturations that exceed the residual liquid saturation) and allows fast screening of optimal injection-gas compositions. We describe construction of the analytical solutions, a process that differs in some ways from related displacements for oil systems. All analytical solutions are verified by numerical calculations.We use an analysis of key equilibrium tie lines that are part of the displacement composition path to demonstrate that the mechanism controlling the development of miscibility in gas condensates may vary from first-contact miscible drives to pure vaporizing and combined vaporizing/condensing drives. Depending on the compositions of the condensate and the injected gas, multicontact miscibility can develop at or below the dewpoint pressure of the reservoir-fluid mixture.Finally, we discuss the possible impact on performance prediction of the formation of a mobile condensate bank at the displacement front in near-miscible gas-cycling/injection schemes.
Design and Productivity of Gravel-Packed Completions
Authors: Penberthy W.L. , Cope B.J. 
Published: December 2007

Field-scale gravel-pack studies have shown that openhole gravel packs have higher productivity than cased-hole gravel packs; however, in the latter, well productivity can be improved by increasing the size and number of perforations. Results also show that cased-hole gravel-pack productivity can be enhanced by prepacking gravel outside the perforations.

Introduction
Gravel packing to exclude formation sand from produced fluids has been used as a completion technique for oil and gas wells for the past 40 to 50 years. However, the technology used in early gravelpack work was borrowed from the water-well industry, which for many years had been applying several types of mechanical sand retention devices to prevent sand production from produced groundwater.Early oil and gas completions, similar to those used in water wells, were what normally is referred to as openhole gravel packs (Fig. 1). Accurately sized gravel was placed around a slotted liner to act as a filter for formation sand. Subsequent completions sometimes consisted of cementing casing through the formation and perforating to communicate with the oil reservoir. This technique became common with the advent of gun and jet perforating, because the exclusion of water or gas was sometimes difficult to achieve in openhole gravel packs.If fluid production also resulted in sand production, cased-hole gravel packs were performed inside the well's casing (Fig. 1). The well productivity of these packs, however, quickly was recognized as being far below that experienced with the openhole packs. Field experience showed that, in general, the productivity of prepacked cased-hole completions was sometimes only 25 to 33% of that of the openhole pack, whereas the lack of prepacking could cause productivity losses of greater than 95%, as shown in Table 1.As a result of these problems, a whole new dimension in gravel packing arose with the cased-hole gravel-pack completion, since substantially different techniques and procedures are required to perform these completions properly in comparison with openhole gravel packs.The productivity limitations encountered in cased-hole gravel packs prompted numerous engineers and researchers to begin work to define and solve problems related to them. Early work on the proper gravel size required for effective sand control indicated that gravel/sand ratios of from 5:1 to 13:1 should be used. Formation sand design points anywhere from a cumulative of 10 to 70% based on a representative formation sand sample were recommended.Most of the early research was conducted in linear-flow packs operated under single-phase flow conditions. Additional work indicated that the main restriction to flow was sand-filled perforations and that for maximum productivity, plugging in the perforation with formation sand must be avoided. The remedy for this situation has been to pressure-pack the gravel through the perforation so that the gravel in the perforation is of the highest permeability capable of preventing the production of formation sand.
JPT
P. 1679＾
Entrainment and Deposition of Fine Particles in Porous Media
Authors: Gruesbeck C. , Collins R. E. 
Published: December 2007

AbstractEntrainment and redeposition of naturally occurring fine particles in porous media has been suggested as a mechanism leading to abnormal decline in productivity of producing wells. This paper describes the results of studies conducted to determine factors affecting this phenomenon. Experimental work done as part of this study provides the basis for a proposed phenomenological theory of entrainment and deposition. The central concept of this theory is representation of both particle and pore size distributions by partitioning the porous medium at any cross section into parallel plugging and nonplugging pathways. This simple model appears to be completely adequate for describing a broad class of filtration and entrainment phenomena. We have shown that fines entrainment and redeposition are mechanisms that can cause abnormal productivity decline and are phenomena restricted to the near-wellbore region.
A Recipe for Residual Oil Saturation Determination
Authors: Kidwell Charles M. , Guillory Abner J. 
Published: December 2007

Before initiation of a CO2 tertiary recovery project, a residual oil saturation study was conducted in the deep, hot, pilot reservoir. The paper discusses the many technical problems that had to be resolved before and during the study. The problems confronted are outlined so that the procedure can be used much like a cookbook in designing future studies in similar reservoirs.

Introduction
With the advent of increased oil prices, tertiary recovery techniques are becoming more economically attractive. The necessity for residual oil saturation measurements will become more common since these numbers are mandatory in defining the profitability of any tertiary project. Routine procedures to measure this saturation in situ become necessary. However, we are dealing with such a delicate system that the details of planning such an operation become very involved.In 1978 Shell Oil Co., in conjunction with the U.S. DOE, conducted a residual oil saturation study in a deep, hot, high-pressured U.S. gulf coast reservoir. The work was conducted before initiation of a CO2 tertiary recovery pilot.Primary discussion in this paper centers around planning and results of a "log-inject-log" (LIL) operation used as a prime method to determine the residual oil saturation. Several independent methods were used to calculate the residual oil saturation in the subject well in an interval between 12,910 and 12,920 ft (3935 and 3938 m). In general, these numbers were in good agreement and indicated a residual oil saturation between 22 and 24%.A free-gas saturation was measured in the residual oil saturated interval. This saturation may well be typical of U.S. gulf coast reservoirs that are below the original bubble point at the time tertiary recovery is initiated. As a result, residual oil saturation typically may be less than those values determined by "flood pot" or countercurrent imbibition tests run in the laboratory. Likewise, residual saturations conventionally measured by openhole resistivity and porosity logs may be residual hydrocarbon and not residual oil saturations.The test was conducted in the "S" Sand Reservoir B (SRB), a 12,800-ft (3901-m) deep U.S. gulf coast reservoir in Weeks Island field, Iberia Parish, LA. The project setting is depicted in Fig. 1. The SRB initially contained two oil columns with more than 3 million bbl (476,700 m3) of in-place oil. Virtually all of this was in the pilot area. Before initiation of the tertiary project, the SRB had been flooded with fresh water. The remaining oil column had been produced to an estimated thickness of 23 ft (7 m). The 900 acre-ft (1 110 140 m3) of the SRB we propose to displace should contain a minimum of 258,000 bbl (40 996 m3) of water-drive residual oil. If the process is proved successful in the SRB, other major watered-out reservoirs in Weeks Island field have an estimated tertiary potential of 26 million bbl (4 131 400 m3) of oil which could be recovered by CO2 displacement.
JPT
P. 1999＾
Water Flooding a High Water-Cut Strawn Sand Reservoir
Authors: Roebuck I.F. , Crain Leon L. 
Published: December 2007

Abstract
The Baylor County Water flood Unit No. 1 is located in the East Seymour Strawn field, approximately 11 miles east of the city of Seymour, Tex. Production is from a stratigraphic-trap Strawn sand reservoir at an average depth of approximately 4,675 ft, with the reservoir almost completely underlain by water. After seven years of primary production with a partial water-drive mechanism, and with producing water-cut at an average of 75 per cent, the field was unitized and a downdip peripheral water-injection project was installed. This paper discusses the geology, rock and fluid properties, and field producing characteristics. The producing history, before and after the beginning of injection, is presented as are the detailed projections of both primary and water-injection performances and the various factors considered in the design of this successful water-injection program.
Introduction
The Baylor County Waterflood Unit No. 1, operated by Sheets and Walton Drilling CO. of Breckenridge, Tex., is located in the East Seymour Strawn field, Baylor County, Tex. (Fig. 1). This field is approximately 11 miles east of the city of Seymour in Sections 196, 197, 206 and 207 of the T. and N. O. R. R. Survey. The producing reservoir is a stratigraphic-trap Strawn sandstone of Pennsylvanian age with an active, but limited, aquifer. By July, 1960, when water-injection operations were initiated, oil producing rates had declined to less than 8 B/D/well, and the producing water-cut had increased to an average of 75 per cent. In spite of the adverse geological conditions present with respect to water content and position in the reservoir, unitized water- injection operations have been both economically and technically successful. This paper presents the geological and engineering data and interpretations which led to the application of water- injection operations, and describes the production performance under injection operations.
History and Development
Production in the vicinity of the Baylor County Waterflood Unit No. 1 was discovered in June, 1950, with the completion of the J.J. Lynn, First National Bank of Fort Worth No. 1 well as a Caddo lime producer (Fig. 2). In Sept., 1951, the J.J. Lynn, First National Bank of Bowie No. 1 well was completed as a Strawn sand producer in what was designated as the Seymour Strawn field with a total of 11 producing oil wells. The East Seymour Strawn field was discovered in Sept., 1952, with the completion of the J.J. Lynn, Claude Cowan "H" No. 1 well. By Dec., 1955, a total of 24 Strawn sand oil wells had been completed, 23 of which were in what is now designated as the Baylor County Waterflood Unit No. 1 (i.e., the Cowan "B", "J" and "H" leases, Sections 206 and 207, T. and N. O. R. R. Co. Survey, Baylor County, Tex.).
JPT
P. 845ˆ
ASP System Design for an Offshore Application in La Salina Field, Lake Maracaibo
Authors: Hernández Clara , Chacón Larry J. , Anselmi Lorenzo , Baldonedo Abel , Qi Jie , Dowling Phillip C. , Pitts Malcolm J. 
Published: December 2007

SummaryLa Salina Field, on the eastern coast of Lake Maracaibo, Venezuela, was designated as a Laboratorio Integrado de Campo (Integrated Field Laboratory, or IFL) by PDVSA to evaluate the potential application of different EOR processes. One of the main goals at La Salina IFL was to evaluate the alkaline-surfactant-polymer (ASP) technology potential in an oil reservoir near the end of its waterflood life.La Salina produces a medium-gravity crude oil (25°API) from the LL-03/Phase III Miocene reservoir at 915 m (3,000 ft). The feasibility of applying the ASP technology was based on a series of experiments including fluid compatibility, chemical thermal stability, phase behavior, interfacial tension between crude oil and ASP solution, chemical retention by the porous media, and physical simulation with reservoir core samples. The laboratory design involved 23 commercial surfactants, five polymers, and two alkalis. Interfacial tension reductions in excess of 25,000-fold were observed for a variety of ASP solutions. Type II- and Type III phase behaviors were observed. Linear coreflood results indicate that high-molecular-weight, partially hydrolyzed polyacrylamide polymers can be injected into La Salina sand. Radial sandpack floods produced an average oil recovery of 45.6% original oil in place (OOIP) with water injection. Injection of 30% pore volume of ASP solution, followed by 30% pore volume of polymer drive solution, produced (on average) an additional 24.6% OOIP for an average total oil recovery of 70.2% OOIP.The design of the injection plant for La Salina is a challenging task because this will be the first offshore application of the ASP technology in the world. The initial decision for the plant design was to use an existing platform instead of a barge for the construction of facilities. As a result, critical parameters such as treatment sequence, equipment footprint, and storage space for injected and treatment chemicals were considered. Preparation and transport of a phase-stable ASP solution through the injection lines and into the reservoir are crucial. Designed chemical concentrations and physical characteristics must be maintained.
Theoretical and Experimental Investigation of Isothermal Compositional Grading
Authors: Ratulowski J. , Fuex A. N. , Westrich J. T. , Sieler J. J. 
Published: December 2007

Summary
A centrifuge system capable of producing a potential difference across a live oil column equivalent to 1,000 ft of gravitational head was designed and tested. Initial tests on a simple ternary system yielded results similar to equation-of-state (EOS) models. A black-oil sample from a Gulf of Mexico field, Bullwinkle J2-RB sand, exhibiting compositional gradients was segregated in the centrifuge. Experimental results from the centrifuge were similar to field values, indicating that the large variation in composition observed for this field may be attributed to gravitational segregation alone.
From the results of these two sets of experiments and the subsequent analysis of the graded fractions, we can conclude that significant compositional variation of reservoir fluids not near their vapor/liquid critical points can be caused by gravity alone. The grading phenomenon is sensitive to the saturate/aromatic balance of the oil. Existing EOS models did not correctly predict the compositional variations in fluids like the Bullwinkle J2-RB because pseudocomponents generated from volatility distributions have a fixed saturate/aromatic character. It is subtle changes in the saturate/aromatic balance that drive the grading phenomena for these fluids.
Improved Permeability Estimates in Carbonate Reservoirs Using Electrofacies Characterization: A Case Study of the North Robertson Unit, West Texas
Authors: Mathisen Trond , Lee Sang Heon , Datta-Gupta Akhil 
Published: December 2007

SummaryWe propose a simple, cost-effective approach to obtaining permeability estimates in heterogeneous carbonate reservoirs using commonly available well logs. Our approach follows a two-step procedure. First, we classify the well-log data into electrofacies types. This classification does not require any artificial subdivision of the data population but follows naturally based on the unique characteristics of well-log measurements, reflecting minerals and lithofacies within the logged interval. A combination of principal component analysis (PCA), model-based cluster analysis (MCA), and discriminant analysis is used to identify and characterize electrofacies types. Second, we apply nonparametric regression techniques to predict permeability using well logs within each electrofacies.Our proposed method has been successfully applied to the North Robertson Unit (NRU) in Gaines county, west Texas. Previous attempts to derive permeability correlations at the NRU have included rock-type identification using thin-section and pore-geometry analysis that can sometimes be expensive and timeconsuming. The proposed approach resulted in improved permeability estimates, leading to an enhanced reservoir characterization, and can potentially benefit both daily operations and reservoir simulation efforts. The successful field application demonstrates that the electrofacies classification used in conjunction with sound geologic interpretation can significantly improve reservoir descriptions in complex carbonate reservoirs.
Asphaltene Precipitation and Alteration of Wetting: The Potential for Wettability Changes During Oil Production
Authors: Al-Maamari Rashid S. H. , Buckley Jill S. 
Published: December 2007

Summary
Wettability controls the distribution and flow of immiscible fluids in an oil reservoir and thus plays a key role in any oil-recovery process. Once thought to be a fixed property of each individual reservoir, it is now recognized that wettability can vary on both microscopic and macroscopic scales. Polar oil components can adsorb onto the pore-bounding mineral surfaces by several different mechanisms. In this study, we explore a transition in the mechanism of wettability alteration that relates to the asphaltene fraction and its stability in the oil phase.
Asphaltene stability was varied by adding n-heptane to samples of five crude oils. Conditions tested ranged from those in which asphaltenes were stable to mixtures in which aggregates formed and separated from the oil. The onset condition—in which the first asphaltene particles become visible—provides a reference point with respect to asphaltene stability in each crude-oil sample.
Muscovite mica sheets, treated with brine and with the crude oil/heptane mixtures, were examined using contact angles between decane and water as a measure of altered wettability on the oil-treated surfaces. A significant increase in oil-wet conditions very near the onset of asphaltene precipitation was observed with four of the five oils, indicating the potential for wetting changes during the course of oil production if conditions of asphaltene instability are approached. Implications of changes in the mechanism of wetting alteration during the course of production from an oil reservoir are considered.