bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Special Enzymes as a Means To Remove Formation Damage Induced by Drill-in Fluids in Horizontal Gas Wells in Tight Reservoirs
Authors: Siddiqui M. A. , Nasr-El-Din H. A. 
Published: April 2006

SummaryDrill-in fluids contain biopolymers such as xanthan gum, cellulose, and/or starch, along with bridging agents like sized calcium carbonate particles. These polymers are used to enhance the carrying capacity of the mud and to form a filter cake to minimize leakoff of the drilling fluids into the formation.Proper removal of drilling-mud filter cake is essential to minimize formation damage. The damage becomes more intense in tight formations, especially in horizontal gas wells in which the drawdown is not high enough to dislodge the filter cake. Another source of damage is the mud filtrate where fines migration and water blockage can occur in tight formations, especially in sandstone reservoirs.A thorough laboratory investigation of formation damage induced by drill-in fluids (water-based) was conducted. A mini-flow loop was used to assess formation damage induced by polymers present in the drill-in fluid. Various cleaning fluids were examined and their effectiveness in removing the filter cake was determined. These fluids included acidic brines, surfactants, mutual solvents, specific enzymes, and combinations of these fluids. The retained permeability of reservoir cores was determined for each cleaning system. This paper presents results obtained from the laboratory and recommendations made to remove drilling-mud filter cake from horizontal gas wells in a deep sandstone-gas reservoir.
Upscaling and 3D Streamline Screening of Several Multimillion-Cell Earth Models for Flow Simulation
Authors: Samantray Ajay K. , Dashti Qasem M. , Ma Eddie D. C. , Kumar Pradeep S. 
Published: April 2006

Summary
Nine multimillion-cell geostatistical earth models of the Marrat reservoir in Magwa field, Kuwait, were upscaled for streamline (SL) screening and finite-difference (FD) flow simulation.
The scaleup strategy consisted of (1) maintaining square areal blocks over the oil column, (2) upscaling to the largest areal-block size (200×200 m) compatible with 125-acre well spacing, (3) up-scaling to less than 1 million gridblocks for SL screening, and (4) upscaling to less than 250,000 gridblocks for FD flow simulation. Chevron's in-house scaleup software program, SCP, was used for scaleup. SCP employs a single-phase flow-based process for upscaling nonuniform 3D grids. Several iterations of scaleup were made to optimize the result.
Sensitivity tests suggest that a uniform scaled-up grid overestimates breakthrough time compared to the fine model, and the post-breakthrough fractional flow also remains higher than in the fine model. However, preserving high-flow-rate layers in a nonuniform scaled-up model was key to matching the front-tracking behavior of the fine model. The scaled-up model was coarsened in areas of low average layer flow because less refinement is needed in these areas to still match the flow behavior of the fine model. The final ratio of pre- to post-scaleup grid sizes was 6:1 for SL and 21:1 for FD simulation.
Several checks were made to verify the accuracy of scaleup. These include comparison of pre- and post-scaleup fractional-flow curves in terms of breakthrough time and post-breakthrough curve shape, cross-sectional permeabilities, global porosity histograms, porosity/permeability clouds, visual comparison of heterogeneity, and earth-model and scaled-up volumetrics.
The scaled-up models were screened using the 3D SL technique. The results helped in bracketing the flow behavior of different earth models and evaluating the model that better tracks the historical performance data. By initiating the full-field history-matching process with the geologic model that most closely matched the field performance in the screening stage, the amount of history matching was minimized, and the time and effort required were reduced. The application of unrealistic changes to the geologic model to match production history was also avoided.
The study suggests that single realizations of "best-guess" geo-statistical models are not guaranteed to offer the best history match and performance prediction. Multiple earth models must be built to capture the range of heterogeneity and assess its impact on reservoir flow behavior.
An Analytical Model for Production Decline-Curve Analysis in Naturally Fractured Reservoirs
Authors: Li Kewen , Horne Roland N. 
Published: April 2006

SummaryDecline-curve-analysis models are used frequently but still have many limitations. Approaches of decline-curve analysis used for naturally fractured reservoirs developed by waterflooding have been few. To this end, a decline-analysis model derived on the basis of fluid-flow mechanisms was proposed and used to analyze the oil-production data from naturally fractured reservoirs developed by waterflooding. Relative permeability and capillary pressure were included in this model. The model reveals a linear relationship between the oil-production rate and the reciprocal of the oil recovery or the accumulated oil production. We applied the model to the oil-production data from different types of reservoirs and found a linear relationship between the production rate and the reciprocal of the oil recovery as foreseen by the model, especially at the late period of production. The values of maximum oil recovery for the example reservoirs were evaluated with the parameters determined from the linear relationship. An analytical oil-recovery model was also proposed. The results showed that the analytical model could match the oil-production data satisfactorily. We also demonstrated that the frequently used nonlinear type curves could be transformed to linear relationships in a log-log plot. This may facilitate the production-decline analysis. Finally, the analytical model was compared with conventional models.
Self-Learning Reservoir Management
Authors: Saputelli L. , Nikolaou M. , Economides M. J. 
Published: April 2006

SummaryIn this work, we present an industrial automation framework for control and optimization of hydrocarbon-producing fields while satisfying business and physical constraints. The all-encompassing reservoir-management problem is decomposed into a hierarchy of decision-making problems at different time scales.We exemplify the proposed approach through a case study on a multiple-layer reservoir with a classical waterflood problem, in which a numerical reservoir model is used as a virtual field. A model-predictive control (MPC) strategy is used to regulate well and field instrumentation at economically optimal set points determined by an overlying supervisory control level. The study demonstrates significant reduction in water-handling costs and increased oil recovery.This work is a starting point for further development in automatic intelligent reservoir technologies, which capitalize on the abilities of permanent instrumented wells and remotely activated downhole completions.
Pt. McIntyre: A Case Study of Gas Enrichment Above MME
Authors: Moulds T. P. , McGuire P. L. , Jerauld G. R. , Lee S.-T. , Solano R. 
Published: April 2006

Summary
Pt. McIntyre field operates an enriched-gas-injection scheme that displaces oil in a multicontact miscible (MCM) displacement achieved through a combined condensing/vaporizing (C/V) mechanism. A range of miscible-injectant (MI) compositions, varying from the minimum miscible enrichment (MME) to substantially above the MME, is available to the project. Field-scale numerical-simulation studies for the Pt. McIntyre field show that incremental oil recovery is nearly doubled when using the richest available MI composition.
At the MME, dispersion can act to substantially reduce oil recovery by reducing the concentration of enriching components in the near-miscible zone. Increasing enrichment above the MME compensates for this action. Accurate predictions of incremental oil depend on the numerical dispersion in a simulator being able to match the impact of physical dispersion. We show how compositional core data from an MI-swept interval provide confirmation of the impact of dispersion at field scale and demonstrate the appropriateness of the simulation model. The benefit of enrichment appears to be robust to the variation of reservoir description found at Pt. McIntyre and to whether the MI application targets incremental oil through liquid- or vapor-phase recovery.
Previous studies into MI enrichment have reported that for a four-component system, the mechanism changes from C/V to purely condensing as the enrichment level approaches first-contact miscibility (FCM). We show that with the addition of a small amount of heavy component, the C/V behavior is retained with increasing enrichment until transition into FCM. This makes it unlikely that a transition to a purely condensing mechanism will occur in real reservoirs.
Integration of Seismic Anisotropy and Reservoir-Performance Data for Characterization of Naturally Fractured Reservoirs Using Discrete-Feature-Network Models
Authors: Will Robert , Archer Rosalind , Dershowitz Bill 
Published: April 2006

SummaryThis paper proposes a method for quantitative integration of seismic (elastic) anisotropy attributes with reservoir-performance data as an aid in characterizing systems of natural fractures in hydrocarbon reservoirs. This method is demonstrated through application to history matching of reservoir performance using synthetic test cases.Discrete-feature-network (DFN) modeling1 is a powerful tool for developing fieldwide stochastic realizations of fracture networks in petroleum reservoirs. Such models are typically well conditioned in the vicinity of the wellbore through incorporation of core data, borehole imagery, and pressure-transient data. Model uncertainty generally increases with distance from the borehole. Three-dimensional seismic data provide uncalibrated information throughout the interwell space. Some elementary seismic attributes such as horizon curvature and impedance anomalies have been used to guide estimates of fracture trend and intensity (fracture area per unit volume) in DFN modeling2 through geostatistical calibration with borehole and other data. However, these attributes often provide only weak statistical correlation with fracture-system characteristics.The presence of a system of natural fractures in a reservoir induces elastic anisotropy that can be observed in seismic data. Elastic attributes such as azimuthally dependent normal moveout velocity (ANMO), reflection amplitude vs. azimuth (AVAZ), and shear-wave birefringence can be inverted from 3D-seismic data. Anisotropic elastic theory provides physical relationships among these attributes and fracture-system properties such as trend and intensity. Effective-elastic-media models allow forward modeling of elastic properties for fractured media.A technique has been developed in which both reservoirperformance data and seismic anisotropic attributes are used in an objective function for gradient-based optimization of selected fracture-system parameters. The proposed integration method involves parallel workflows for effective elastic and effective permeability media modeling from an initial DFN estimate of the fracture system. The objective function is minimized through systematic updates of selected fracture-population parameters. Synthetic data cases show that 3D-seismic attributes contribute significantly to the reduction of ambiguity in estimates of fracture-system characteristics in the interwell rock mass. The method will benefit enhanced-oil-recovery (EOR) program planning and management, optimization of horizontal-well trajectory and completion design, and borehole-stability studies.
Completion and Well-Performance Results, Genesis Field, Deepwater Gulf of Mexico
Authors: Pourciau Robert D. , Fisk Jill H. , Descant Frank J. , Waltman R. Bart 
Published: April 2006

Summary
The Genesis project was Chevron Corp.'s first Gulf of Mexico deepwater development project and the first industry project to use spar technology for drilling, completion, and production operations.1,2 This paper discusses the unique results and lessons learned through the first 4 years of the Genesis project in the areas of integrated teams, organizational learning, spar operations, completion practices, well performance, and reservoir management.
Natural Polymer-Based Compositions Designed for Use in Conformance Gel Systems
Authors: Reddy B. R. , Eoff Larry , Dalrymple E. Dwyann , Brown David 
Published: April 2006

SummaryThis article describes a crosslinking material derived from natural sources that can be used with a variety of polymers over a broad temperature range to produce gels for conformance applications. Delayed crosslinked polymer systems have been used for many years in conformance applications. For the past decade, the most widely used system has been based on chromium (+3) crosslinked polyacrylamide. Organic crosslinkers, such as phenol/formaldehyde and polyethyleneimine (PEI), have also been used with a variety of polymers. However, these systems are being scrutinized by regulatory agencies and have now been scheduled for phase-out in some countries. Because of these issues, a single, environmentally friendly crosslinker that could be used with a variety of polymers over a broad temperature range was selected for study.This article details the laboratory development of an environmentally friendly, natural polyamine crosslinker system, namely chitosan. This crosslinker can be used with a variety of polymers, such as polyacrylamide, AMPS/acrylamide (AMPS/AA), or alkylacrylate polymers. Gels ranging from stiff and "ringing" type to "lipping" have been obtained. Additionally, this article summarizes results from recent efforts targeted toward designing chitosan-basedgel compositions with improved environmental rating for potential field use. These efforts included using chitosan as the base polymer in combination with asynthetic polymeric crosslinker, as well as developing gels derived completelyfrom natural polymers.
The Use of Lightweight Cement Slurries and Downhole Chokes on Air-Drilled Wells
Authors: Brown Devin , Ferg Thomas 
Published: April 2006

SummaryThe success of a primary cement job is often measured according to effective zonal isolation, achieving the designed top of cement, and avoidance of remedial cementing. In the San Juan and Rio Arriba counties of New Mexico, many Mesa Verde and Dakota wells are air-drilled because the Mesa Verde formation is subnormally pressured and naturally fractured. This combination makes the Mesa Verde easy to hydraulically fracture during normal drilling and cementing operations. Therefore, meeting the primary-cement-job success criteria is particularly challenging.Cementing of casing within an air-drilled wellbore allows the slurry to free fall. Cement free fall can cause severe surge pressures at the bottom of the hole, leading to hydraulic fracture initiation and loss of lift. Theuse of a downhole choke (DHC) can be employed to prevent these processes from occurring.Because mud filter cake does not exist in an air-drilled hole, the lead water spacer and cement must wet the casing and wellbore rock surfaces. Loss of the lead water spacer, in conjunction with cement water loss, can produce dehydration of the cement column, leading to an increase incement viscosity and equivalent circulating density. Careful control of cement-free water and fluid loss are required to prevent this from occurring. Further more, placing cement across targeted completion intervals that have low fracture gradients requires the use of ahigh-compressive-strength, low-density cement that is competent and capable of maintaining zonal isolation during the completion and production phases of well construction.This paper will outline the evolution of the cementing practices used forthe Mesa Verde and Dakota wells drilled in the 29-6 Unit (T29N−R6W, New Mexico) from 1998 to 2002. It will illustrate how cementing changes enabled the primary cementing to be successfully completed in a single stage instead of two, which has translated into cost savings for both the drilling and completion phases of a well. The impact of using a DHC for the pumping and placement of these primary cement jobs will be illustrated and discussed. The function of the cement additives on slurry properties will also be discussed as they pertain to these cement jobs.
The Small-Drillhole Minipermeameter Probe for In-Situ Permeability Measurement
Authors: Dinwiddie C. L. 
Published: April 2006

SummaryLaboratory measurement of permeability using a Hassler cell is the industry standard; however, consistently removing undisturbed rock samples from friable outcrops is difficult. Although various conventional surface-sealing mini-permeameters are developed as an alternative for permeability measurement, these devices generally suffer from difficulties in maintaining optimal forces on the tip seal when dealing with outcrop irregularities in the field; outcrop weathering is also problematic. Because a reliable field method is needed for studies of friable geological units, this paper presents an innovative technique for measuring permeability in situ. The design of the small-drillhole minipermeameter probe is discussed, as well as the accompanying analytical technique and the size and shape of the instrument's averaging volume. Small-diameter holes [i.e., 1.8 cm (0.7 in.)] are drilled into an outcrop with a masonry drill, followed by drillhole vacuuming, probe insertion, seal expansion, gas injection, and calculation of the intrinsic permeability through measurement of the injection pressure, gas-flow rate, and knowledge of the system geometry. Advantages of this approach include access to a nonweathered surface, an operator-independent sealing mechanism around the air-injection zone, and the potential for permeability measurement at multiple depths below an outcrop surface. To date, data have been collected from four diverse porous media: upper and lower shoreface sandstone (Escalante, Utah), saprolitic soils (Clemson, South Carolina), nonwelded and sintered ignimbrite (Bishop, California), and fluvially reworked tuffaceous sedimentary rock (Bishop, California). The probe has proved durable and robust, with a single probe sufficient for making thousands of measurements in a variety of environments. Data quality supports the conclusion that the drillhole probe is a practical field instrument.
In-Situ Diagnosis of Formation Characteristics in Horizontal Wells
Authors: Cui H. , Dong Y. , Kalita R. , Sinha S. , Jalali Y. 
Published: April 2006

SummaryA method is presented for estimating the distribution of a parameter related to the productivity index along the length of a liner-completed horizontal well, using measurements of well flowing pressure at multiple points along the path of flow in the wellbore. This is the concept of near-wellbore diagnosis with multipoint pressure measurements, which in principle can be made with fiberoptic sensors. The deployment mechanism of the sensors is not modeled in this study, although the temperature version of such sensors has been deployed in horizontal wells on an extended-tailpipe or stinger completion. (The temperature sensors also have been deployed in horizontal wells with sand-screen completions, in direct contact with the formation, but that configuration is not investigated in this study.)The parameter that is estimated is known in reservoirsimulation terminology as the connection factor (CF), which represents the hydraulic coupling or connectivity between the reservoir and the wellbore (between formation gridblocks and well segments). Parameter CF has units of md-ft, similar to flow capacity, or productivity index multiplied by viscosity. Specifically, the parameter is directly proportional to the geometric mean of the permeability perpendicular to the horizontal axis of the well and is inversely related to skin. No attempts are made in this study to estimate these parameters individually, which may require recourse to other methods of well diagnosis (e.g., dynamic formation testing, transient analysis, and production logging).The method applies to flow under constant-rate conditions and yields estimates of the CF, which represents the quality of the formation in the vicinity of the well and the integrity of the completion along the well trajectory.The quality of the inversion is determined by the spatial density and accuracy of the multipoint measurements. Inversion quality also depends on knowledge of the wellbore hydraulic characteristics and the relative permeability characteristics of the formation. The basic configuration investigated in this study consists of a five-node pressure array in a 2,000-ft horizontal well experiencing a total pressure drop of approximately 60 psi when produced at 10,000 STB/D. A reasonable estimate of the distribution of the parametric group CF is obtained even when allowing for measurement drift and errors in liner roughness and relative permeability exponent. Also, the inversion can be rendered insensitive to knowledge of the far-field permeability through a scaling technique. Therefore, good estimates of the near-wellbore CF profile can be obtained with uncertain knowledge of the reservoir permeability field. This is important because the technique can be applied not only to early-time but also to late-time data. The application of the multipoint pressure method is illustrated through a series of examples, and its potential for near-wellbore formation evaluation for horizontal wells is described.
A Recent Gulf of Mexico Cavity Completion
Authors: Palmer Ian , Vorpahl Douglas G. , Glenn John M. , Vaziri Hans , McLennan John 
Published: April 2006

SummaryProduction was dramatically improved by cavitating (i.e., intentionally producing sand) an offshore gas well on the Gulf of Mexico shelf. The cavity completion was conducted over a period of 10 days and involved producing the well with temporary equipment to safely produce, collect, and dispose of the produced sand. No hydrocarbon emissions resulted because production could be routed back through the permanent facilities. Following the operations, the well was returned to flow through the permanent facilities at a much higher producing rate, with much lower sand production.Before the cavity-completion operations, the well had been choked back to a low gas rate (&lt;1 MMscf/D) because of sand production. The low gas rate was insufficient to continuously lift liquids, causing the well to become liquid loaded and/or slug. The well was evaluated for a sand-control completion, but this type of repair was believed to entail too much economic risk because of significant reservoir unknowns. Further evaluation suggested that the well had the attributes for successful cavity completion.This paper discusses the cavity-completion evaluation process employed and the operational results and learnings; a similar process may be applicable too ther wells.