bluuebunny/crossref_metadata_2025_split huggingface dataset:
Building a System in a Service Company To Assure Technical Integrity and Institutionalize Organizational Learning
Authors: Rixse M. G. , Thorogood J. L. 
Published: December 2007

Summary
A service company and operator worked together to build a system to assure technical integrity within the service company's field operating unit. They created systems and procedures to address how the service company was organized; how it performed design, how it executed the service, and how it managed the logistical issues associated with performing the service. The procedures were structured to facilitate the gathering and application of new knowledge.
The process was initially tackled from an ISO 9000 quality management standpoint, but the result lacked usefulness and was rejected. A more direct and universal approach was adopted that emphasized the safety-critical and cost-critical processes that are paramount requirements of an oilwell service operation.
Development of these systems required extensive thought to define the exact scope of the issues that needed to be addressed. The system had to be structured so that it would be actively utilized and not become a bureaucratic burden. Significant organizational culture changes were required to encourage personnel to learn and operate within the defined procedures. Using commonly available computer software, systems were implemented that provided access to the policies and procedures actively used by both the operator and the service company. The computer software furnished a simple framework to promote learning within the contractor's organization.
Directional Drilling and Earth Curvature
Authors: Williamson H. S. , Wilson H. F. 
Published: December 2007

Summary
This paper provides a review of current practices for calculating directional drilling placement in the light of modern extended-reach applications. The review highlights the potential for gross errors in the application of geodetic reference information and errors inherent in the calculation method. Both types of error are quantified theoretically and illustrated with a real example. The authors borrow established land surveying calculation methods to develop a revised best practice for directional drilling. For the elimination of gross errors they prescribe increased awareness and a more disciplined approach to the handling of positional data.
Mechanical Strength of Reservoir Materials: Key Information for Sand Prediction
Authors: Zhang J. J. , Rai C. S. , Sondergeld C. H. 
Published: December 2007

Summary
The mechanical strength of a reservoir formation is the most crucial information required for predicting sand production and recommending sand control completion. So far, the only reliable technique to obtain the formation strength quantitatively is to perform laboratory tests on core samples. The laboratory tests require substantial volumes of cores, which in most cases are not available. In this study, we present a new method to avoid this restriction. The significance of this approach is in its simplicity and efficiency in constructing a reliable mechanical failure envelope. The key results of this study, based on measurements on a variety of sandstones, are the following.
A single normalized failure envelope characterizes sandstone formations. This universal curve makes it possible to construct the failure envelope for a sandstone formation from the knowledge of critical pressure. There exists a correlation between the critical pressure and the compressional wave velocity (at equivalent depths of burial). The failure envelope for a sandstone formation can then be constructed simply from compressional wave velocities. These velocities are generally accessible from conventional logging data.
Interrelationship of Wettability, Initial Water Saturation, Aging Time, and Oil Recovery by Spontaneous Imbibition and Waterflooding
Authors: Zhou Xianmin , Morrow N. R. , Ma Shouxiang 
Published: December 2007

Summary
Previous studies of crude oil/brine/rock (COBR) and related systems showed that wettability and its effect on oil recovery depend on numerous complex interactions. In the present work, the wettability of COBR systems prepared using Prudhoe Bay crude oil, a synthetic formation brine, and Berea Sandstone was varied by systematic change in initial water saturation and length of aging time at reservoir temperature (88°C). All displacement tests were run at ambient temperature. Various degrees of water wetness were achieved and quantified by a modified Amott wettability index to water, the relative pseudowork of imbibition, and a newly defined apparent advancing dynamic contact angle.
Pairs of spontaneous imbibition (oil recovery by spontaneous imbibition of water) and waterflood (oil recovery vs. pore volumes of water injected) curves were measured for each of the induced wetting states. Several trends were observed. Imbibition rate, and hence, water wetness, decreased with increase in aging time and with decrease in initial water saturation. Breakthrough recoveries and final oil recovery by waterflooding increased with decrease in water wetness. Correlations between water wetness and oil recovery by waterflooding and spontaneous imbibition are presented.
Experimental Study of Wettability Alteration to Preferential Gas-Wetting in Porous Media and Its Effects
Authors: Li Kewen , Firoozabadi Abbas 
Published: December 2007

SummaryIn a recent theoretical study, Li and Firoozabadi [Li, K. and Firoozabadi, A.: "Phenomenological Modeling of Critical-Condensate Saturation and Relative Permeabilities in GasCondensate Systems," paper SPE 56014 available from SPE, Richardson, Texas (2000)] showed that if the wettability of porous media can be altered from preferential liquid-wetting to preferential gas-wetting, then gas-well deliverability in gas-condensate reservoirs can be increased. In this article, we present the results that the wettability of porous media may indeed be altered from preferential liquid-wetting to preferential gas-wetting. In the petroleum literature, it is often assumed that the contact angle through liquid-phase θ is equal to 0° for gas-liquid systems in rocks. As this work will show, while θ is always small, it may not always be zero. In laboratory experiments, we altered the wettability of porous media to preferential gas-wetting by using two chemicals, FC754 and FC722. Results show that in the glass capillary tube θ can be altered from about 50 to 90° and from 0 to 60° by FC754 for water-air and normal decane-air systems, respectively. While untreated Berea saturated with air has a 60% imbibition of water, its imbibition of water after chemical treatment is almost zero and its imbibition of normal decane is substantially reduced. FC722 has a more pronounced effect on the wettability alteration to preferential gas-wetting. In a glass capillary tube θ is altered from 50 to 120° and from 0 to 60° for water-air and normal decane-air systems, respectively. Similarly, because of wettability alteration with FC722, there is no imbibition of either oil or water in both Berea and chalk samples with or without initial brine saturation. Entry capillary pressure measurements in Berea and chalk give a clear demonstration that the wettability of porous media can be permanently altered to preferential gas-wetting.
Steady-State Upscaling: From Lamina-Scale to Full-Field Model
Authors: Pickup Gillian , Ringrose P. S. , Sharif Ahmed 
Published: December 2007

Summary
In recent years, the impact of small-scale permeability structure on hydrocarbon recovery has been demonstrated, and upscaling procedures, such as the geopseudo method, have been developed to scale-up from the lamina scale using the hierarchy of geological length scales. However, upscaling is very time consuming, so many engineers still input rock curves into large-scale simulations. In this study, we show how the process may be speeded up using steady-state methods for calculating the pseudofunctions.
Two examples are used to demonstrate the method. The first is a three-stage scale-up of a water flood in a fluvio-aeolian model. Capillary equilibrium was assumed for the first two stages, and viscous-dominated steady state for the third stage. Two different wettability cases were examined—water-wet and intermediate-wet. The effect of using the small-scale pseudo relative permeabilities depends on both the nature of the heterogeneities and on the wettability. In this study the recovery was reduced when small-scale pseudos were included, especially in the water-wet case.
The second case study involved gas injection into the oil leg of a tidal deltaic reservoir. Scale-up was performed in two stages: (a) from the lithofacies scale to the geological model, and (b) from the geological model to the full-field simulation model. The viscous-dominated steady-state method was used in both cases. The results showed that the effect of the fine-scale heterogeneities was of the same order as the effect of the coarse-scale heterogeneity, indicating that (even in a system where capillary pressure is negligible) the fine-scale structure can be important.
Approximate Model for Productivity of Nonconventional Wells in Heterogeneous Reservoirs
Authors: Wolfsteiner Christian , Durlofsky L. J. , Aziz Khalid 
Published: December 2007

SummaryA semianalytical method is presented for the approximate modeling of the productivity of nonconventional wells in heterogeneous reservoirs. The approach is based on Green's functions and represents an extension of a previous model applicable for homogeneous systems. The new method, referred to as the s–k* approach, models permeability heterogeneity in terms of an effective skin s that varies along the well trajectory and a constant background permeability k*. The skin is computed through local, weighted integrations of the permeability in the near-well region and is then incorporated into the semianalytical solution method. The overall method, which can also model effects due to wellbore hydraulics, is quite efficient in comparison to detailed finite-difference calculations.Results for the performance of nonconventional wells in threedimensional heterogeneous reservoirs are computed using the s-k* approach and compared to finite-difference calculations resolved on the geostatistical fine grid. The new method is shown to provide an accurate estimate of wellbore pressure and production rate, as a function of position along the wellbore, for various well configurations and heterogeneous permeability fields. The possible use of the overall approach in a simulation while drilling (SWD) tool, in which the well path and trajectory are "optimized" using real-time data, is also discussed.
Theoretical Model and Numerical Investigation of Near-Wellbore Effects in Hydraulic Fracturing
Authors: Romero Jean , Mack M. G. , Elbel J. L. 
Published: December 2007

Summary
The high near-wellbore pressure drop, which has frequently been reported in fracture treatments, is indicative of ineffective communication between the wellbore and the fracture. Although numerous observations of such effects have been published, few attempts have been made to understand them. This article describes three possible mechanisms of near-wellbore effects [perforation phasing misalignment-induced rock pinching, perforation pressure drop, and fracture reorientation (deviation tortuosity)] and their implementation in a numerical fracture simulator. Typical signatures of all three effects in fracture treatment records are shown, and a method is proposed by which to distinguish them.
Perforation phasing misalignment has been identified as a cause of near-wellbore restriction. Because the fracture does not always initiate at the perforation, the fluid must communicate with the fracture through a narrow channel (microannulus) around the casing. Here we describe this pinching effect and show that it is related to the contact stress between the cement and the formation. Perforation pressure drop and deviation tortuosity, which have previously been proposed by other authors, have also been modeled. They have been incorporated into the simulator, together with the phasing misalignment effect, to allow investigation of the differences in response between the different mechanisms. Results of simulating the effects of erosion of near-well effects on treating pressure are also shown.
Comprehensive field cases studies exhibiting near-wellbore mechanics are presented. The relevant near-wellbore mechanism is first identified and the downhole pressure is then simulated, demonstrating the validity of the model.
New Approach for Enhancing Fracture Conductivity
Authors: Nguyen P. D. , Dewprashad B. T. , Weaver J. D. 
Published: December 2007

Summary
A new liquid surface-modification system was developed for coating proppant, dramatically increasing its surface friction and allowing it to interact instantaneously with surrounding particulates. High surface friction between coated proppant grains allows them to withstand high flow rates, minimizing their flowback potential after fracture-stimulation treatments.
According to field results, when this surface-modification material was used as a flowback-control agent after conventional fracturing treatments, it permitted more aggressive flowback procedures. This treatment did not impair conductivity, and, in fact, increased proppant conductivity at closure stresses below 4,000 psi. Better vertical proppant distribution occurred in experiments that demonstrated how the surface modification significantly hindered proppant settling. Fines that already existed within the prop-pant (generated from the formation or derived from crushed proppant upon fracture closure) all adhered to the treated proppant, which inhibited them from migrating and blocking pore throats of the proppant pack. This unique coating technology further enhanced conductivity by improving fracturing-gel breaker action in certain fluids. This behavior results in faster, more effective well cleanup after stimulation.
Laboratory, Theoretical, and Field Studies of Emulsified Acid Treatments in High-Temperature Carbonate Formations
Authors: Navarrete R. C. , Holms B. A. , McConnell S. B. , Linton D. E. 
Published: December 2007

SummaryEmulsified acids were traditionally used in acid fracturing, and more recently on matrix treatments of carbonate formations. The delayed nature of emulsified acids is useful in generating longer etched fractures or deeper wormholes. Emulsified acids also have higher viscosities than straight acid, which reduces fluid loss in acid fracturing applications and helps distribute acid more uniformly in formations with high-permeability contrast during matrix treatments. A new emulsified acid system is presented in this paper that is stable up to 350°F, highly retarded, and significantly more viscous than straight acid. Laboratory data comparing emulsified acid with straight acid are presented at temperatures ranging up to 350°F, including rheology and acid conductivity. Field case histories in the Smackover formation in Alabama over two years are presented. The field case histories show the improvements in production of oil and gas resulting from emulsified acid fracturing treatments in comparison with prior similar treatments done with straight acid.
Modeling Scale-Inhibitor Treatments in Horizontal Wells: Application to the Alba Field
Authors: Mackay E. J. , Matharu A. P. , Sorbie K. S. , Jordan M. M. , Richard Tomlins 
Published: December 2007

SummaryMany horizontal wells produce both oil and brine for an extended period of time and, therefore, in many cases the problem of mineral scale deposition must be solved. Scale management in long horizontal wells faces several challenges, a major one being the correct placement of the scale inhibitor slug in the formation. Accurate placement is required to ensure that vulnerable well sectors are treated, without wasting chemical in the protection of zones which will not cut water during the lifetime of the squeeze treatment.This paper presents results from a novel nearwellbore simulator (assist2), which is used to model scale inhibitor treatments in horizontal wells. A technique for modeling such treatments has been developed which gives an improved understanding of where the chemical will be placed under different injection strategies, and how the placement will impact the squeeze life. It also allows the engineer to assess the impact of varying such parameters as inhibitor slug volume and concentration, overflush volume, injection rate, etc. Different inhibitor chemicals can be compared for their performance under the given reservoir conditions.This technique has been applied to model a squeeze treatment in a horizontal well where good production data are available. Connection oil and water flow rates, calculated by a full-field simulation model, have been matched by assist2. Various treatment designs were tested to assess the impact of the controllable parameters listed above. Findings enabled a treatment to be specified that was predicted to increase the squeeze lifetime without increasing the volume of chemical required. This modeled application strategy will also reduce the initial inhibitor concentration spike in the return curve. The performance of various chemicals under reservoir flow conditions was modeled, with a clear best choice emerging from these studies.Based on the findings of this modeling work, recommendations were made for a squeeze treatment, which were implemented, and the resulting field data are presented.
Development of a Downhole Oil/Water Separation and Reinjection System for Offshore Application
Authors: Bowers B. E. , Brownlee R. F. , Schrenkel P. J. 
Published: December 2007

Summary
Hydrocyclone-based systems for downhole separation of produced oil and water and subsequent disposal of the produced water by reinjection within the same wellbore have been successfully applied in a number of onshore wells. Benefits of these systems include reduced produced water lifting and disposal costs, as well as a significant reduction in liquid load on surface processing facilities.1 Reduction in surface equipment requirements is of primary interest in offshore applications, where significant reduction in the size and cost of surface separation facilities promises to extend field life and make marginal developments economically viable. Further development of downhole separation and reinjection systems is underway in order to provide a range of hardware systems suitable for a variety of offshore applications.
Mobility Ratio - Its Influence on Injection or Production Histories in Five-Spot Water Flood
Authors: Aronofsky J.S. , Ramey H.J. 
Published: December 2007

Abstract
Potentiometric model studies of the five-spot water flood to determine the influence of mobility ratio upon injection or production histories are described. The results, suggest a method for the correlation of data from field pilot tests for the estimation of an effective mobility ratio and its effect upon field water floods. The effect of the well spacing-to-well radius ratio upon production histories is presented. A method of accounting for this factor is suggested. The influence of injection (or production) rates and injection and production well pressures upon production histories is shown. The fivespot well pattern was investigated for water-to-oil mobility ratios of 0.1 to infinity.

Introduction
It has been well established that mobility ratio has an important effect upon flood patterns. It should be equally apparent that injection and production histories must also be influenced by mobility ratio. However, none of the articles referred to above mention the importance of being able to predict the effect of well pressures (or injection rates) during the entire time history of a waterflood operation. A complete description of production histories (the terms "injection" and "production" are synonymous for the steady-state model under consideration) would provide values for well pressures and interface positions at any time for a specified injection rate. Conversely, if the waterflood problem is specified in terms of a constant injection well pressure, then it would be desirable to know the injection rate and interface positions at any time.
Differential-Sticking Mechanisms and a Simple Wellsite Test for Monitoring and Optimizing Drilling Mud Properties
Authors: Reid P. I. , Meeten G. H. , Way P. W. , Clark Peter , Chambers B. D. , Gilmour Alan , Sanders M. W. 
Published: December 2007

Summary
Differential sticking has a major impact on drilling efficiency and well costs. It is known to be influenced by drilling-fluid properties and other parameters, such as the characteristics of rock formations. Mechanisms of differential sticking were investigated using laboratory data and information in the literature. The knowledge gained was used to design a simple and robust device for measuring the sticking properties of drilling fluids, both in the laboratory, or at the well site.
This device comprises a half-area high-pressure, high-temperature (HPHT) fluid-loss cell, modified to allow a metal sphere to be placed in contact with a growing mud filter cake. The torque required to rotate the sphere free from the mud cake is determined using an electronic torque gauge. A plot of torque against the 3/4 power of time gives a linear fit to the data. The slope of this line is indicative of the sticking potential of the mud.
Laboratory and field data indicate that the test gives a good indication of mud condition and allows the user to investigate various options for reducing the sticking potential of the fluid. This information is useful both in the initial selection of mud type and in making technical and economic analyses of various mud treatment options. In addition to the laboratory evaluation described above, the sticking device has been used in several well-site tests with encouraging results. Some of these are described.
Flow Visualization Studies of Solution Gas Drive Process in Heavy Oil Reservoirs With a Glass Micromodel
Authors: Bora R. , Maini B. B. , Chakma A. 
Published: December 2007

Summary
A series of flow visualization experiments was carried out to examine the pore scale behavior of the solution gas drive process in heavy oil reservoirs. The main objective was to testify several speculative theories that had been put forward to explain the anomalous production behavior of heavy oil reservoirs producing under the solution gas drive process. Contrary to previous postulations, the asphaltene constituents did not appear to play a significant role in the nucleation and stabilization of the gas bubbles that evolved during the solution gas drive process. Experimental evidence also suggests that the production of heavy oil is not accompanied by a large population of microbubbles. These observations suggest that the production enhancement in the solution gas process in heavy oil reservoirs may be related to other mechanisms such as viscous coupling effects, sand production, wormhole effects, etc.