bluuebunny/crossref_metadata_2025_split huggingface dataset:
Surface BOP: Testing and Completing Deepwater Wells Drilled With a Surface-BOP Rig
Authors: Mason D. L. , Tharp W. , Wilie C. L. 
Published: April 2006

Summary
Many deepwater-development projects in operators' portfolios require lower costs to meet internal economic thresholds. Because of this, Shell has looked at extending surface-blowout-preventer (BOP) activities to include well testing and completion techniques for deepwater wells in conjunction with surface-BOP drilling.
The cost advantages of surface-BOP-drilled wells have been demonstrated (notably in the Far East), but the recent surface-BOP-drilled well in Brazil is a milestone in terms of extending the applicability to deeper water and harsher environments. The enabling technology has been the subsea isolation device (SID). Testing and completion techniques have been developed to be compatible with surface-BOP wells drilled with an SID.
This paper focuses on the following aspects:
Well testing using surface-BOPs from a moored rig and Well completions using surface-BOPs from a moored rig.
Shell has developed a testing configuration to carry out a DST, essentially using standard equipment. The well-testing equipment configuration is currently ready for use and has been run in a subsea-BOP well.
In completion operations, the availability of a high-pressure (HP) riser does not add significant complexity and even actually simplifies some of the completion activities. Conceptual studies and early hazard/risk assessments have shown there are no obvious "showstoppers," and the duration of a surface-BOP-rig completion is expected to be very similar to a subsea-BOP-rigcompletion.
This paper describes the results of the conceptual studies, early hazard assessment exercises used to define the basic design parameters, and more detailed hazop studies.
Bounds on In-Situ Stress Magnitudes Improve Wellbore Stability Analyses
Authors: Aadnøy Bernt S. , Hansen Ann K. 
Published: April 2006

Summary
Wellbore stability analysis is becoming a necessary tool to improve operational economy and to avoid wellbore problems. Essential elements of this process include estimation of critical fracturing and collapse pressures to obtain an optimal mud-weight window.
The input data for this analysis is mainly pore pressure predictions from many sources such as logs and drilling exponents, overburden stresses from logs or drilled cuttings, leakoff tests at casing shoes, and breakout analysis from caliper logs. From these and other data, estimates for in-situ stresses and directions are obtained, which again serve as input for wellbore stability modeling. It is evident that the input data come from many different sources and can therefore not be considered consistent.
During wellbore stability modeling, it has often been observed that unrealistic results appear. Sometimes one observes a critical collapse pressure that exceeds the fracturing pressure, clearly a faulty result. There is often an inherent error in some of the input data. This paper addresses this problem and concludes that the relative magnitudes of the in-situ stresses are its main cause. Equations are given that define the bounds on the in-situ stresses for different stress regimes.
By using the bounds on the horizontal in-situ stresses on field cases, realistic fracturing and collapse prognosis are always obtained. Because the models also define the minimum permissible anisotropic stress state, these can be used as default parameters when field data are missing.
A field case from the North Sea demonstrates the application of the stress bounds and shows that prognoses are obtained that better correspond to observed behavior of the wells.
A Model for Changes in Coalbed Permeability During Primary and Enhanced Methane Recovery
Authors: Shi Ji-Quan , Durucan Sevket 
Published: April 2006

SummaryThe natural fracture network of a dual-porosity coalbed reservoir is made up of two sets of orthogonal, and usually subvertically oriented, cleats. Coalbed permeability has been shown to vary exponentially with changes in the effective horizontal stress acting across the cleats through the cleat-volume compressibility, which is analogous to pore compressibility in porous rocks. A formulation for changes in the effective horizontal stress of coalbeds during primary methane recovery, which includes a Langmuir type curve shrinkage term, has been proposed previously. This paper presents a new version of the stress formulation by making a direct link between the volumetric matrix strain and the amount of gas desorbed. The resulting permeability model can be extended readily to account for adsorption-induced matrix swelling as well as matrix shrinkage during enhanced methane recovery involving the injection of an inert gas or gas mixture into the seams. The permeability model is validated against a recently published pressure-dependent permeability multiplier curve representative of the San Juan basin coalbeds at post-dewatering production stages. The extended permeability model is then applied successfully to history matching a micropilot test involving the injection of flue gas (consisting mainly of CO2 and N2) at the Fenn Big Valley, Alberta, Canada.
Predicting Carbonate Scale in Oil Producers From High-Temperature Reservoirs
Authors: Ramstad Kari , Tydal Trine , Askvik Kjell Magne , Fotland Per 
Published: April 2006

SummaryCalcium carbonate (CaCO3) scale is a common problem in the oil industry, leading to reduced well performance and obstruction of safety valves. Recent field experiences indicate that scaling may be a problem at lower saturation ratio (SR) than earlier anticipated. In a high-pressure, high-temperature scale cell, crystal growth in synthetic formation water has been studied. Induction times and growth rates have been determined by use of a microscope cell. The results have been interpreted by use of nucleation theory. The findings indicate that wells may be safely operated at SR below 2.5 at 85°C. At higher temperature, crystal growth is less dependent on SR and the temperature dominates the system. Care should therefore be taken when operating wells at temperatures greater than 100°C.
Multiresolution Wavelet Analysis for Improved Reservoir Description
Authors: Sahni Isha , Horne Roland N. 
Published: April 2006

SummaryIt is well documented that history matching is a problem with possibly nonunique solutions. In the past few years, several automated or semiautomated history-matching algorithms have been proposed. Depending on the algorithm used, it is possible that the final estimated reservoir-property distribution that allows for a good history match may not be geologically realistic. Therefore, there is a need to include other constraints to generate multiple, geologically realistic history-matched realizations. These constraints might, for example, include the variogram, a training image, the distribution of net-to-gross, pore volume, or other geostatistical information about the reservoir. This inclusion is particularly useful because it introduces uncertainty information in the reservoir description when we have limited history from existing wells in the field and intend to drill infill wells or implement a secondary-recovery process.The algorithm proposed in this paper uses multiresolution wavelet analysis to integrate history data with the geostatistical information contained in the variogram proposed for the reservoir. Wavelets allow the representation and manipulation of property distributions at various resolutions at the same time. Using wavelets, information from different sources such as production history and seismic surveys (that would be at different resolutions) can be incorporated directly at the appropriate resolution level. In the first step, we fix the wavelet coefficients sensitive to the history-match data. This has the effect of fixing the field history without fixing individual gridblock properties. In the second step, the remaining free wavelet coefficients are modified to integrate variogram information into the reservoir description. Generating multiple realizations of only the second set of wavelets coefficients results in multiple history-matched, variogram-constrained descriptions of the reservoir. The computational investment is very modest because the history match is done only once.In a number of example cases, different areal Gaussian fields with varying amounts of available production-history data were studied to test the algorithm. It was found that the wavelet coefficients constraining the history can be decoupled from those constraining the variogram. The implication of this observation is that the history data and variogram can be integrated sequentially into the reservoir model—that is, after the initial history match, new information can be added to the model without disturbing the original match to yield multiple history-matched and geostatistically constrained realizations.
The Cement-to-Formation Interface in Zonal Isolation
Authors: Ladva H. K. J. , Craster B. , Jones T. G. J. , Goldsmith G. , Scott D. 
Published: April 2006

SummaryMaintaining zonal isolation for the lifetime of oil and gas wells is critical. Leakage behind casing can reduce the cost effectiveness of the well and cause health and safety risks from pressure buildup and contaminated aquifers. During the completion and production phases of the well, temperature and pressure variations can cause stresses at the cement-to-formation interface. The ability of the casing-cement system to maintain a seal at the cement-to-formation interface depends on the condition of the formation surface before slurry placement. The condition of shale will depend upon the nature of the drilling fluid used, whereas the condition of a permeable rock will depend upon the presence and nature of the filter-cake deposited during drilling and circulation.In this paper, we present an improved understanding of chemical interactions at the cement-to-formation interface and the factors that determine bond strength and the position of the plane of failure. For permeable formations, the role of the mud filter cake for different mud types is explored. For nonpermeable formations, the presence and effect of a mud treatment are also examined. The extent and depth to which chemical alteration of the mudcake occurs when in contact with cement is determined together with measurements of the yield stress and water-content profile of the altered mudcake. The effecton bond strength of exposing swelling and nonswelling shales to inhibitive drilling fluids is presented. Laboratory-scale test equipment and a small-scale wellbore simulator, developed for tests under realistic field conditions, are described. A flexible (i.e., lower Young's modulus) cement plays a role in bonding and is demonstrated by the simulator tests. This improved understanding enables us to confirm the key issues at the cement-to-formation interface and propose some solutions for effective zonal isolation.
Innovative Remedial Cementing Solution Provides Annular Isolation in Duyong B-4
Authors: Morris Thomas C. , Bidi M. Zuki , Elmarsafawi Y. , Nair Devan , Said Rifat , Tugcu Reha , Ong Jane 
Published: April 2006

SummaryWhether a cement-squeeze operation results in an annular seal depends heavily on how far the cement can penetrate and disperse in the fine channels of a partially cemented annulus. In many cases, a conventional- or microfine-cement slurry will dehydrate and bridge off before it can achieve its objectives (Nelson et al. 1990). This paper describes the use of an engineered, optimized slurry for a squeeze operation in the Duyong B-4 well, which had a perforated zone that demonstrated a low rate of seawater injectivity. This paper also presents the slurry design and properties, execution procedure, and prejob and post-job log evaluations.After several years of production, gas bubbles appeared in various locations throughout the Duyong field. Shallow seismic readings showed gas charging in several shallow gas layers throughout the Duyong field. Several wells were investigated as possible contributors to the charging of the shallow sandstone layers, and Duyong B-4 was selected as a probable contributor. Duyong B-4 is a gas well that was completed in November 1983 with four producing zones. In September 2003, this well was selected as a test well to evaluate the cement quality behind the casing. Both cement-bond logs and ultrasonic-imaging logs showed gas and fluid channels behind the casing. An optimized cement slurry (OCS) was engineered and tested in the laboratory under well conditions. Results showed excellent penetration in narrow gaps, optimum fluid-loss control, and low rheology, both at surface and downhole conditions.The slurry was used in the squeeze operation; post-job logs demonstrated the success of the treatment. The slurry penetrated the narrow gaps without dehydrating, and good mechanical properties were achieved in short setting times (Moulin et al. 1997). These properties are especially important in gas-producing wells, and they met all the objectives set forth by the client.
Optimization of Coalbed-Methane-Reservoir Exploration and Development Strategies Through Integration of Simulation and Economics
Authors: Clarkson C.R. , McGovern J.M. 
Published: April 2006

Summary
The unique properties and complex characteristics of coalbed methane (CBM) reservoirs, and their consequent operating strategies, call for an integrated approach to be used to explore for and develop coal plays and prospects economically. An integrated approach involves the use of sophisticated reservoir, wellbore, and facilities modeling combined with economics and decision-making criteria.
A new CBM prospecting tool (CPT) was generated by combining single-well (multilayered) reservoir simulators with a gridded reservoir model, Monte Carlo (MC) simulation, and economic modules. The multilayered reservoir model is divided into pods, representing relatively uniform reservoir properties, and a "type well" is created for each pod. At every MC iteration, type-well forecasts are generated for the pods and are coupled with economic modules. A set of decision criteria contingent upon economic outcomes and reservoir characteristics is used to advance prospect exploration from the initial exploration well to the pilot and development stages. A novel approach has been used to determine the optimal well spacing should prospect development be contemplated. CPT model outcomes include a distribution of after-tax net present value (ATNPV), mean ATNPV (expected value), chance of economic success (Pe), distribution of type-well and pod gas and water production, reserves, peak gas volume, and capital. An example application of CPT to a hypothetical prospect is provided.
An integrated approach also has been used to assist with production optimization of developed reservoirs. For example, an infill-well locating tool (ILT) has been constructed to provide a quick-look evaluation of infill locations in a developed reservoir. ILT, like CPT, is used for multiwell applications, combining the single-well simulator with a multilayered reservoir model and economics. An application of ILT to a CBM reservoir is provided, and the results are compared with the predictions of an Eclipse* reservoir simulation.
Controls of Coal Fabric on Coalbed Gas Production and Compositional Shift in Both Field Production and Canister Desorption Test
Authors: Cui Xiaojun , Bustin R. Marc 
Published: April 2006

Summary
The production rates of coalbed gas wells commonly vary significantly, even in the same field with similar reservoir permeability and gas content. The compositional variation in produced gas is also not everywhere predictable, although in most fields produced gas becomes progressively enriched in CO2 through the production life of a reservoir, such as parts of the San Juan basin. In contrast, it is generally observed that the ratio of CO2:CH4 declines with time during field and laboratory desorption testing of coal cores. In this study, we investigate numerically the importance of coal fabric, namely cleat spacing and aperture width, on the performance of coalbed gas wells and gas compositional shifts during production. Because of the cubic relationship between fracture permeability and fracture aperture width (and thus fracture porosity) for a given cleat permeability, the production profile of coal seams varies depending on whether the permeability is distributed among closely spaced fractures (cleat) with narrower apertures or more widely spaced fractures (cleat) with wider apertures. There is a lower fracture porosity for coal with widely spaced fractures than for coal with closely spaced fractures. Therefore, the relative permeability to gas increases more rapidly for coals with more widely spaced cleats as less dewatering from fractures is required, assuming that the fractures are initially water saturated. Increase in cleat spacing from 0.01 to 10 cm significantly enhances the peak gas production and shortens the period to reach peak production.
The main stage of gas production is controlled by equilibrium desorption of gas from coals due to the relatively slow changes in reservoir pressure. The enrichment of CO2 in the production gas with time occurs because of the stronger adsorption of coals for CO2 than CH4. However, during desorption of coal cores, CO2 desorbs more rapidly than methane because desorption rate is governed more by diffusion than by sorption affinity, and CO2 has much higher effective diffusivity in microporous coals than CH4. Therefore, during canister desorption, there is a rapid increase in CO2 concentration in the desorbed gas followed by a steady decline in CO2 concentration, in contrast to the progressive enrichment of CO2 in produced gas from wells.
Thermoporoelastic Effect on Wellbore Stability
Authors: Chen Guizhong , Ewy Russell T. 
Published: April 2006

SummaryThis paper presents the consistency of thermal effects (i.e., the thermal-induced pore pressure and rock stresses) between two available models for inclined boreholes. Thermal effects for both a permeable and an impermeable boundary are studied. The solutions of pore pressure and stresses are provided, and the singularity is solved in the solutions for the condition of hydraulic diffusivity being equal to thermal diffusivity. The analytical solutions in the Laplace domain and in the real-time domain are verified using the finite-difference solutions. The collapse failure index and critical mud weights, as well as thermally induced pore pressure, are presented and analyzed under the circumstances of heating and cooling the wellbore. Results show that heating the wellbore can destabilize the near-wellbore region by raising both the collapse and the fracturing mud weight. The model presented in this paper can be applicable to deepwater drilling, where a narrow mud-weight window often occurs.
Subsurface Uncertainty Management and Development Optimization in the Harweel Cluster, South Oman
Authors: O'Dell Mike , Lamers Edwin 
Published: April 2006

SummaryIn the past 5 years, there has been a string of exploration successes in discovering some 350 million m3 (2 billion bbl) of oil in the Harweel Cluster in south Oman. This oil is deep, under high pressure, and comes with a high gas/oil ratio (GOR), and the fluids contain 15% CO2 and 5% H2S. Of the nine Precambrian carbonate reservoirs, six are lithostatically pressured, and three are hydrostatic. The Harweel Cluster is more than 70 km from existing infrastructure. If gas can be reinjected, miscible displacement is expected in many of the reservoirs. The Harweel Cluster is one of Oman's major opportunities for "green field" oil development.There is a large degree of subsurface uncertainty in gross rock volume and oil/water contact (OWC), reservoir architecture, faults and fractures and reservoir compartmentalization, degree of dolomitization, permeability level and heterogeneity, fluid properties, and so on. However, little is known about the scale and relative importance of each of these uncertainties. Some uncertainties, such as compositional grading, might turn out to be more important than anticipated when evaluating development options because of non-linearities and dependencies.Analyzing the effects of all uncertainty combinations in all reservoirs is not a realistic option. Therefore, a structured scenario-based approach has been developed to analyze and assess all potential factors influencing recovery schemes, reserves, and productivity. After evaluating the range of possible values and calculating the impact of each uncertainty, realizations were created to represent the range of possible values in each new reservoir. Field-scale equation-of-state models were used to simulate both primary depletion and gas reinjection. Development scenarios were optimized for each discrete realization. The resulting reservoir models serve as a basis for the development-concept selection and the subsequent field-development plans.
Improved Oil Recovery From Carbonate Reservoirs by Chemical Stimulation
Authors: Xie X. , Weiss W. W. , Tong Z. , Morrow N. R. 
Published: April 2006

Summary
Oil reserves from shallow-shelf carbonate reservoirs account for 22% of the original oil in place (OOIP) of the entire U.S. oil resource. Many of these reservoirs are naturally fractured. A pressure-pulsing technique has been used in fractured fields to improve oil recovery. In some situations, imbibition of water can be promoted by chemical stimulation to alter the reservoir wettability toward water-wetness such that oil is expelled at an economic rate from the rock matrix into fractures. Shallow-shelf (i.e., Class II) carbonate reservoirs typically produce less than 10% OOIP during primary recovery and respond poorly to water injection.
In this work, promotion of imbibition was determined for a cationic surfactant, cocoalkyltrimethyl ammonium chloride (CAC), and a nonionic surfactant, an ethoxylated alcohol (POA). Cores from three dolomitic Class II reservoirs, Cottonwood Creek, Dagger Draw, and Lustre, were used in the laboratory tests. After preparing core samples using the corresponding reservoir crude oil and brine, spontaneous expulsion of oil was measured in glass imbibition cells at elevated temperature for more than 50 core samples. When reservoir brine was used as the imbibition fluid, oil recovery was in the range of 0 to 35% OOIP. After imbibition of reservoir brine had ceased, the cores were transferred into surfactant solutions at or somewhat above the critical micelle concentration (CMC) to test for enhanced recovery by further imbibition. Typically, immersion in the surfactant solution resulted in an additional recovery of 5 to 10% OOIP. The increased recovery is mainly ascribed to increased water–wetness. The effect of acidization before surfactant treatment was also tested and found to be detrimental to oil recovery.