bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Combined Effect of Near-Critical Relative Permeability and Non-Darcy Flow on Well Impairment by Condensate Drop Out
Authors: Blom Saskia M. P. , Hagoort Jacques 
Published: December 2007

SummaryWe present a comprehensive numerical method to calculate well impairment based on steady-state radial flow. The method incorporates near-critical relative permeability and saturation-dependent inertial resistance.Example calculations show that near-critical relative permeability, which depends on the capillary number, and non-Darcy flow are strongly coupled. Inertial resistance gives rise to a higher capillary number. In its turn, the improved mobility of the gas phase caused by a higher capillary number enhances the importance of the inertial resistance.The effect of non-Darcy flow is much more pronounced in gas condensate reservoirs than in dry gas reservoirs. Well impairment may be grossly overestimated if the dependence of relative permeability on the capillary number is ignored.
Horizontal Well IPR Calculations
Authors: Thomas L. K. , Todd B. J. , Evans C. E. , Pierson R. G. 
Published: December 2007

SummaryThis paper presents the calculation of near-wellbore skin and non-Darcy flow coefficient for horizontal wells based on whether the well is drilled in an underbalanced or overbalanced condition, whether the well is completed openhole, with a slotted liner, or cased, and on the number of shots per foot and phasing for cased wells. The inclusion of mechanical skin and the non-Darcy flow coefficient in previously published horizontal well equations is presented and a comparison between these equations is given. In addition, both analytical and numerical solutions for horizontal wells with skin and non-Darcy flow are presented for comparison.
Chemistry and Field Application of an Improved Continuous-Mix Gelled Oil
Authors: Maberry L. J. , McConnell S. B. , Tanner K. V. , Hinkel J. J. 
Published: December 2007

Summary
The introduction of water-base fracturing fluids to water-sensitive formations can be detrimental to well performance. Gelled oil fracturing fluids are often used in water-sensitive formations. However, temperature limitations have typically been associated with gelled oil fluids, especially those used in continuous-mix applications. The chemistry and field application of an improved continuous-mix gelled oil system for use at reservoir temperatures between 75 and 300°F are described. A brief history of oil gelation and phosphate ester chemistry is presented, followed by a discussion of new complexation chemistry. Laboratory data supporting fluid performance are provided. A treatment evaluation is presented on 90 wells fractured in the Wyoming North La Barge area, from August 1994 to October 1996. Gelled oil fracturing treatments performed with prior art chemistry (PAC) are compared to those performed with an enhanced complexation chemistry (ECC).
Novel Dual-Injection System for Water-Shutoff Treatments
Authors: Plahn S. V. , Stevens D. G. , Enkababian P. G. , Anyan S. L. , Feraud J.-P. M. 
Published: December 2007

SummaryThere are numerous water shutoff techniques. One of these is to seal watered-out zones permanently with rigid polymer gelants. This method can be very effective for near-wellbore water flow problems provided the gelant only enters the watered-out interval and does not damage nearby productive pay. Gelant placement can frequently be controlled with mechanical devices, such as packers and bridge plugs; however, gelant may still enter productive pay through flow paths outside the casing. For such cases, mechanical isolation within the well may not suffice, especially if crossflow between zones is high. We discuss a specialized gelant placement technique, referred to as dual-injection, that can be used to address these types of water control problems. Dual injection can be implemented several ways. We discuss some of these, as well as a completely new dual-injection system.
Finite Difference Simulation of Geologically Complex Reservoirs With Tensor Permeabilities
Authors: Lee S. H. , Durlofsky L. J. , Lough M. F. , Chen W. H. 
Published: December 2007

SummaryThe gridblock permeabilities used in reservoir simulation are commonly determined through the upscaling of a fine scale geostatistical reservoir description. Though it is well established that per- meabilities computed in this manner are, in general, full tensor quantities, most finite difference reservoir simulators still treat permeability as a diagonal tensor. In this paper, we implement a capability to handle full tensor permeabilities in a general purpose finite difference simulator and apply this capability to the modeling of several complex geological systems. We formulate a flux con- tinuous approach for the pressure equation by use of a method analogous to that of previous researchers (Edwards and Rogers1; Aavatsmark et al.2), consider methods for upwinding in multiphase flow problems, and additionally discuss some relevant implemen- tation and reservoir characterization issues. The accuracy of the finite difference formulation, assessed through comparisons to an accurate finite element approach, is shown to be generally good, particularly for immiscible displacements in heterogeneous sys- tems. The formulation is then applied to the simulation of upscaled descriptions of several geologically complex reservoirs involving crossbedding and extensive fracturing. The method performs quite well for these systems and is shown to capture the effects of the underlying geology accurately. Finally, the significant errors that can be incurred through inaccurate representation of the full per- meability tensor are demonstrated for several cases.
Injection/Falloff Testing in Heterogeneous Reservoirs
Authors: Banerjee Raj , Thompson L. G. , Reynolds A. C. 
Published: December 2007

SummaryIn this work, we present a new theoretical understanding of pressure data obtained at a water injection well. The theory provides new physical insight into how permeability heterogeneity, saturation gradients, and mechanical skin factor combine to influence the pressure response at the well. Based on the theoretical equations, methods for analyzing injection/falloff pressure data in both homogeneous and radially heterogeneous reservoirs are presented. For homogeneous reservoirs, we present procedures for estimating the mechanical skin factor from injection or falloff pressure data. Our theory provides a procedure for analyzing the pressure re- sponse during the second injection period of a two-rate test. It is shown that the information that can be obtained from a two-rate test is similar to that obtained from a falloff test.
A Review and Analysis of Equipment for Running Electrical Cables Under Pressure
Authors: Cooke A.C.H. , Greer Cecil B. , Scott F.L. 
Published: December 2007

Abstract
Developments in permanent-type well completion techniques have accentuated the need for improved equipment to handle cables under pressure. Existing conventional packoff devices were tested and their dynamic performance established at 200 to 600 psi with electrical conductor cables. A new packoff technique is reported that permits operating stranded cables at moderate running speeds up to pressure as high as 3,000 psi. In the higher pressure ranges a new commercial device is reported for running cables against well pressure as high as 6,000 psi. These new developments open wide the doors to improved well completion practices, resulting in improved well productivity and more precise well control.

Introduction
Field experience with some phases of permanent-type well completions uncover a need for more adequate and simplified means of running conductor cables into wells under pressure. This paper concerns armored electrical cables usually used in service company work, although the findings are equally applicable to other stranded cables.
The construction of a reverse armor electric conductor cable is such that 20 per cent of the cross section area is pore space. The difficulty in sealing this amount of space has dictated, in the past, the use of small diameter cables for even medium pressure work. Early experiments with packing glands used with conductor cables revealed that a complete high-pressure shutoff could only be obtained by filling the pore space within the cable with heavy grease or packing gland pressures, which prohibited or retarded cable movement.
Recently a new concept has developed of handling cables under pressure. Tests have shown that with a stranded cable located in a closely fitting metal sleeve, the flow through and around the cable is not great and can be controlled. This is known as the controlled blow-by principle and its use has opened up a new approach to the stuffing box problem.
NMR as Standard Porosity Tool in the San Jorge Basin: Log Responses and Applications
Authors: Solanet Fernando , Khatchikian Alberto , Breda Eduardo 
Published: December 2007

Summary
This paper describes our experience with nuclear magnetic resonance (NMR) logs since their introduction in the San Jorge basin in June 1995. To date, more than 400 logs have been run by Western Atlas and Schlumberger using Numar's magnetic resonance imaging tool (MRIL) and combinable magnetic resonance (CMR) tools, respectively, and more than 2,000 zones have been perforated and tested. This has allowed us to characterize the response of the tools in shaly and tuffaceous sands, compare the response of the Numar and Schlumberger tools with each other and with cores, detect the limitations of present tool designs, and relate NMR pore-size distribution and permeability to oil production.
Practical Issues of 4D Seismic Reservoir Monitoring: What an Engineer Needs to Know
Authors: Lumley D. E. , Behrens R. A. 
Published: December 2007

Summary
Time-lapse three-dimensional (3D) seismic, which geophysicists often abbreviate to four-dimensional (4D) seismic, has the ability to image fluid flow in the interwell volume by repeating a series of 3D seismic surveys over time. Four-dimensional seismic shows great potential in reservoir monitoring and management for mapping bypassed oil, monitoring fluid contacts and injection fronts, identifying pressure compartmentalization, and characterizing the fluid-flow properties of faults. However, many practical issues can complicate the simple underlying concept of a 4D project. We address these practical issues from the perspective of a reservoir engineer on an asset team by asking a series of practical questions and discussing them with examples from several of Chevron's ongoing 4D projects.
We discuss feasibility tests, technical risks, and the cost of doing 4D seismic. A 4D project must pass three critical tests to be successful in a particular reservoir: Is the reservoir rock highly compressible and porous? Is there a large compressibility contrast and sufficient saturation changes over time between the monitored fluids? and Is it possible to obtain high-quality 3D seismic data in the area with clear reservoir images and highly repeatable seismic acquisition? The risks associated with a 4D seismic project include false anomalies caused by artifacts of time-lapse seismic acquisition and processing and the ambiguity of seismic interpretation in trying to relate time-lapse changes in seismic data to changes in saturation, pressure, temperature, or rock properties. The cost of4D seismic can be viewed as a surcharge on anticipated well work and expressed as a cost ratio (seismic/wells), which our analysis shows ranges from 5 to 35% on land, 10 to 50% on marine shelf properties, and 5 to 10% in deepwater fields. Four-dimensional seismic is an emerging technology that holds great promise for reservoir management applications, but the significant practical issues involved can make or break any 4D project and need to be carefully considered.
Predicting Displacement Efficiency From Water-Cut or Gas-Cut Field Data
Authors: Welge H.J. 
Published: December 2007

Welge, H.J., SPE-AIME, Petroleum Research Consultants, Inc.
A procedure for predicting oil-displacement efficiency using field data is presented. The method is somewhat simpler than previous methods and is particularly applicable when well are previous methods and is particularly applicable when well are not developed in a regular pattern.

Introduction
A method for predicting the efficiency of oil displacement using field data is presented. The method is particularly applicable when the wells are not developed in a regular pattern, such as alternating rows of injection and producing pattern, such as alternating rows of injection and producing wells, or five-or nine-spot patterns.We assume, nevertheless, that the displacement occurs in a more or less linear manner, as in the portion of an oil field shown in Fig. 1. Here there is a single north-to-south trending row of water injection wells drilled near the center line of the field. The injected water flows mainly toward the east or the west, displacing the oil toward the other (producing) wells. The method presented is somewhat simpler and more straightforward than previous methods.
Procedure Procedure We need, first, an average plot showing fw (the fraction of water in the flowing stream delivered at a well under reservoir conditions) as a function of pore volumes of injection, Wi. To arrive at Wi, we draw a rectangle on the areal map of the oil field (Fig. 1). Two of the opposite sides of this rectangle lie along the direction of average flow of fluids; and these two sides if extended, each pass midway between two injection wells. The other two sides of the rectangle pass through the injection well and nearest producing well, respectively. Thus, this producing well can be considered as withdrawing a "sample" of the fluids flowing past it. The pore volume of the porous body lying under the rectangle, divided into the cumulative volume of water injected into (or through) the rectangle, gives Wi. For Wells I-2 and P-1 in Fig. 1, the fw vs Wi plot shown in Fig. 2 is a reasonable average of the plots for other neighboring wells for which adequate data are available.The scatter of points shown in Fig. 2 is caused partly by the fact that the fw values are obtained from field data by an incremental or derivative process, which tends to magnify any inaccuracies in measurement and any errors caused by shifting streamlines when neighboring wells come on or off stream.To proceed with the displacement prediction, the first step is to arrive at the average water saturation, Sw, in the rectangle that includes Wells I-2 and P-1 (Fig. 1). This average saturation at any throughput will be given by the area above and to the left of the fw vs Wi curve (the smooth curve in Fig. 2) as follows:
Volume of water displaced = .........(1)
where Qi is the total fluid produced at reservoir conditions.
Volume of water injected = .............(2)
Volume of water left inside porous body= .........................(3)
Dividing by the pore volume gives..................(4)
JPT
p. 944
Pompano Through-Flowline System
Authors: Kleinhans J. W. , Cordner J. P. 
Published: December 2007

Summary
The Pompano field development was done in two phases. The first phase consisted of installing a deep water platform, topsides and export pipelines in 1994. The second phase consisted of installing a 10-well subsea oil production template in 1995 and tying it back to the host platform. The subsea template system, which incorporates through-flowline (TFL) well servicing capability, is discussed in this paper. The subsea system, with emphasis on the TFL aspects is described and costs are provided. A single-phase, steady-state, isothermal circulation model is described. This model was used during predesign to aid simulation of the wide range of TFL system operating conditions that are expected during field life. Actual field experience that has been gained since start up of the subsea system in 1996 demonstrates the value of doing this type of hydraulic modeling. Further TFL-related development work is needed to extend TFL capabilities beyond those applied at Pompano, and these development needs are discussed. Conclusions are provided at the end of the paper.
A Simplified Model for Oil/Water Flow in Vertical and Deviated Wellbores
Authors: Hasan A. R. , Kabir C. S. 
Published: December 2007

SummaryThis paper presents the results of an experimental study and a semitheoretical analysis of two-phase oil/water flow in vertical and deviated systems. The study focuses on water-dominated flow regimes, where the patterns may be termed as bubbly flow, pseudoslug flow, and churn flow. A drift-flux approach is taken to analyze the flow behavior of oil/water systems. For the three flow regimes investigated, the drift velocity of the lighter oil phase is found to be dependent on its in-situ volume fraction in addition to the terminal bubble- or droplet-rise velocity. For flow in both vertical and deviated pipes, we were able to develop a single expression for the drift flux, uow, resulting in a single equation for the in-situ oil fraction, fo, for the three flow regimes studied. We correlated fo with the oil superficial velocity, vos, and the terminal rise velocity, vꝏθ, using the expression, fo=vos/{1.2vm + vꝏθ f(1 — fo)2}. In a deviated pipe, the terminal rise velocity, vꝏθ, is correlated with that in a vertical pipe by =vꝏ/'″ (cosθ)0.5(1 + sinθ)2, for θ &lt;70°. The performance of the proposed method in estimating fo is in good agreement with our measurements. Published data further augment the approach presented here.
Graphical Solution of Imbibition Equations Used To Predict Oil Recovery by Water Influx in Naturally Fractured Reservoirs
Authors: Aguilera Robert 
Published: December 2007

Introduction
This article presents graphical solutions to some imbibition equations that describe the recovery of oil from naturally fractured reservoirs with water influx. The equations, presented originally by Aronofsky et al., can be written as
Equation(1)
for the case of a single-model element and
Equation(2)
for the case of a total fractured reservoir where the velocity of advance of the water table is uniform.
In Eqs. 1 and 2, r is recovery at any time t, R is the limit toward which the recovery converges, and X is a constant giving the rate of convergence. By abstract reasoning, these equations have proven to be useful in practical situations. Working the solution by hand, practical situations. Working the solution by hand, however, is difficult because it requires a trial-and-error effort to determine the constants X and R.
The basic assumptions describing the abstract model are (1) the oil production from a small volume, dv, of porous matrix saturated with oil at time zero is a porous matrix saturated with oil at time zero is a continuous monotonic function of time, and it converges to a finite limit, and (2) none of the properties that determine the rate of convergence change sufficiently during the process to affect this rate or the limit. This implies, for example, that variations in wettability and residual oil saturation are not accounted for.
The charts presented in this article were generated to simplify the solution. They are based on work presented by Kern to analyze fouling problems in heat presented by Kern to analyze fouling problems in heat exchangers. (Full-scale graphs are available to the interested reader upon request.)
Notice that the graphical solutions are limited to cases where the continuous monotonic function is of the assumed exponential form. For other cases, a quantitative analysis is not possible.
JPT
P. 1526
Experimental Waterflooding Recoveries Above and Below the Bubble Point
Authors: Bass Daniel M. , Crawford Paul B. 
Published: December 2007

Abstract
Laboratory investigations have been made to study the effect of variations in fluid characteristics, gas saturation, water saturation, and water injection rate on oil recovery by water flooding. Three synthetic gas-saturated crude oils having bubble points of 860, 1,540 and 1,885 psi were used as reservoir fluids. Repeated tests were made in which a sand pack, saturated with water and synthetic oil, was produced by solution gas drive followed by water flooding at various pressure levels. Oil recovery by solution gas drive and subsequent water injection is shown to vary with the pressure and rate at which the water flood is conducted. The pressure at which optimum flooding conditions exist is shown to be a function of the physical characteristics of the reservoir fluid. For the systems studied, increases in oil recoveries of near 10 per cent were obtained by flooding at the most desirable conditions. Variations in initial water saturations gave results similar to those in the literature.

Introduction
Most of the waterflooding studies investigating means of improving present exploitation processes have been conducted at low pressures with little effort to simulate reservoir conditions. Holmgren and Morsel performed a waterflooding study at 300 to 500 psi wherein the gas saturation was created by injecting gas, letting dissolved gas evolve from the oil, and then flushing the core with "live" oil until the desired gas saturation was obtained. Their results show increasing oil recoveries with increasing gas saturations. Data presented by Guerrero and Kennedy, et al, indicate that in some instances waterflooding at approximately 500 psi below the original bubble point results in a lower residual oil saturation than is obtained when water flooding above the bubble point. In their work gas saturations were created by primary depletion. By correcting low pressure flooding data for fluid shrinkage, Dyes found that a maximum oil recovery may be obtained by flooding with initial gas saturations of from 7 to 12 per cent.