bluuebunny/crossref_metadata_2025_split huggingface dataset:
Permeability Modeling for the SAGD Process Using Minimodels
Authors: McLennan J. A. , Deutsch C. V. , Garner D. , Wheeler T. J. , Richy J. -F. , Mus E. 
Published: December 2007

Abstract
The predicted flow performance of Steam Assisted Gravity Drainage (SAGD) well pairs is sensitive to the spatial distribution of permeability. A number of permeability measurements are taken from small scale core plug data. The data may be taken preferentially from certain geologic locations and there may be inconsistencies in the data. The measurement scale is significantly less than that required for input to flow simulation. Mini-models of porosity and permeability are constructed and flow simulated in order to establish representative relationships/correlations at the grid block scale used in SAGD flow simulation. The mini-models are constructed on a by-facies basis honoring the spatial variability within each category. The uncorrected mini-model flow results lead to a too-narrow range of permeability. Geostatistical scaling laws are applied to correct the permeability values.
This paper presents a permeability modeling procedure with application to the Surmont Lease in Northern Alberta, Canada. The mini-model construction, flow simulation of the mini-models, and derivation of representative porosity-permeability statistics are described and documented in this context. A comparison of SAGD flow simulation results (recovered bitumen and steam-oil-ratio) with different permeability modeling procedures is presented to support the relative importance of modeling permeability. The legitimacy of any particular permeability model can only be compared to or validated with comparison to actual flow performance at some time in the future, which is a difficult task. Even with actual flow data, this is a difficult task. This will occur at the Surmont project, at some point in the future.
Advancement in Completion Technologies Proves Successful in Deepwater Frac-Pack and Horizontal Gravel-Pack Completions
Authors: Lorenz M. , Ratterman G. , Martins F. , Triplett W. 
Published: December 2007

Abstract
When operating companies and the service companies combine teamwork and technology development with cohesive communication and planning, the result is proper integration of multi-discipline technologies to ensure successful field applications. The authors will outline some of the obstacles encountered and describe how the tools and procedures were designed to optimize reliability and achieve completions with better well life.
Completion case histories are reviewed for wells in Brazil's offshore and deepwater Campos Basin, and deepwater Gulf of Mexico. The discussion addresses well planning, pumping operations, frac-pack design, selection of well screens with extended longevity and fluid systems that prevent formation damage.
Openhole deviated and horizontal completions continue to be a primary method for reducing cost and improving recovery by maximizing reservoir contact. Integrating this technology with Intelligent Well Systems achieves a significant reduction in the number of wells required to maximize well productivity and reservoir drainage. Openhole completions have been utilized to successfully develop many of the reserves in offshore Brazil. These completion types include horizontal producers and injectors, gravel packs, stand alone screens, openhole gravel packs with annular isolation and integration of Intelligent Well Systems.
Globally, technology has enabled the successful application of gravel packs in lateral lengths exceeding 8,300 feet, and water depths exceeding 6,100 feet. The growth of frac packing in deepwater Gulf of Mexico has intensified engineering efforts to meet the demands specified by the operating companies for fracturing formations with high permeability. Frac-pack applications in deep water can require pump rates exceeding 60 barrels per minute and proppant concentrations of 15 ppa. Specialized tools and performance software have advanced to address the increasing demands and risk management required in today's deepwater market. The evolution of technology is enabling reduced operations risk, better reliability and enhanced oil recovery.
Multidisciplinary Teamwork Results in Dramatically Improved Production— East Kamennoye, Western Siberia
Authors: Mack D. J. , Bitter M. R. , Galchenko R. , Meyer V. , Housman J. 
Published: December 2007

Abstract
The Vikulov formation in the Tyumen District of southwestern Siberia consists of incised-valley deposits and shallow-marine delta-front sands, which form oil reservoirs in the area of the Krasnoleninsk dome. Reservoir quality varies considerably depending on the depositional facies. In places, high permeability channels and bars were deposited, whereas the more distal sands have much lower permeability and must be fracture stimulated to produce economically. To compound the situation, the Vikulov sands are in the transition zone, and in many places, wet sands are in close proximity to the oil-productive sands. For this reason, many of the initial completions within the acreage had poor results.
To improve field performance, a multi-disciplinary team was assembled. The team consisted of a geologist, petrophysicist, completion, production and reservoir engineers, facilities personnel and service company engineers. Their task was to better understand the properties of the Vikulov and the reservoir, determine well locations with maximum production potential, optimize stimulation treatments and provide infrastructure to produce the oil.
This paper will review the initial completion efforts and explain the methodology and changes implemented by the team to describe and define the reservoir, modify stimulation methods using a grid-based, non-coupled fracture simulator and optimize well productivity. Production increases in excess of five fold have been realized for many wells.
New Fluid Technology Improves Performance and Provides a Method to Treat High-Pressure and Deepwater Wells
Authors: Crews J. B. , Huang T. , Wood W. R. 
Published: December 2007

Abstract
For a number of years, visco-elastic surfactant (VES) fluids have been used for a variety of stimulation treatment applications, including hydraulic fracturing, acid diverting, and gravel packing. VES fluid systems typically offer higher retained permeability and conductivity of the formation sand and proppant pack than polymeric systems. However, preliminary cost, a 200°F temperature limit, excessive leak-off, and no internal breaker mechanism for dry gas applications have limited VES use.
New VES fluid technology has been developed that substantially improves product performance and cost effectiveness. The temperature range has been extended to 300°F by using newly developed VES stabilizer technology. The system works with high-density brines up to 14.4 ppg. Internal breakers have been developed that permit controlled viscosity break from ambient to 300°F. Laboratory tests have determined that an internally broken fluid rapidly achieves &gt;90% returned permeability and conductivity of the formation sand and proppant pack without the presence or need for contacting hydrocarbons. Fluid loss control technology has been developed that reduces VES fluid leak-off similar to wall-building fluids, but without filtercake damage.
This paper discusses the development of the new VES system chemistry and its properties. The paper also addresses the merits of a viscous fluid that can work in a variety of base fluids for high-pressure applications such as managing surface treating pressure or for gas hydrate inhibition in deep gas or deepwater environments. Breaker technology discussion addresses the ability to ensure and enhance VES fluid viscosity breaking. Fluid loss control technology effective to at least 2000 md is presented. This paper also presents rheological, return permeability and conductivity, fluid loss control, treating pressure, and financial results.
Experimental Investigation and Modeling of the Effects of Rising Gas Bubbles in a Closed Pipe
Authors: Al-Darmak S. , Falcone G. , Hale C. P. , Hewitt G. F. 
Published: December 2007

Abstract
Transient multiphase flow in the wellbore causes problems in well test interpretation when the well is shut-in at surface and the pressure is measured down-hole. Pressure build-up (PBU) data recorded during a test can be dominated by transient wellbore effects (i.e. phase change, flow reversal and re-entry of the denser phase into the producing zone), making it difficult to distinguish between true reservoir features and transient wellbore artefacts (Gringarten et al., 2000).
This paper is a follow up to SPE 96587 (Ali et al., 2005), which presented experimental results of phase redistribution effects on PBU data. Though the results of the experiments were revealing, they are complex as they reflect the real well situation. To obtain results in which the phase redistribution in the well is studied independently of the interaction with the reservoir, a further set of experiments were carried out, in which the tube (simulating the well) was isolated at both the top and the bottom at the same time. The pressure distribution was measured during the transient following shut-in and for the steady-state final condition in which there was a liquid- filled zone at the bottom of the test section and a gas-filled zone at the top. A substantial number of tests were conducted in the bubbly flow region and could therefore be analysed by a simple one-dimensional model for bubbly flow. The results of the comparison between the model and the experimental data are presented in this paper.
The Future of Drilling-Grade Barite Weight Material—A Case for a Substitute Specification
Authors: Bruton J. R. , Bacho J. , Newcaster J. A. 
Published: December 2007

Abstract
Drilling grade barite, the fundamental drilling fluids "weight material" for over 8 decades, remains the primary source of ore product to adjust drilling mud densities around the world. However, quality, economically viable, and attainable supplies of 4.2 specific gravity barite ore for oilfield use are rapidly depleting. This is particularly true in the North American market, where significant foreign imports of barite ore are required to meet high demands from deepwater, Central US, and Western Canada drilling regimes. Without significant worldwide investments to locate and produce material to meet current API 4.2 s.g. and contaminant specifications, it is unlikely that producers of drilling grade barite will be able to supply the industry with a low-cost product in just a few short years. A viable alternative for less critical drilling applications is to use 4.10 specific gravity ore that possesses all the quality specifications of the current material.
Industry acceptance of this reduced specific gravity material, co-existing with the current standard, could extend barite supplies by 5 years, or more, with only modest investment. The intent of this paper is to share results from a strategy now being undertaken to introduce and demonstrate the viability of the substitute specification ore in US applications. Also presented are laboratory studies that show that use of the 4.10-s.g. substitute will have minimal impact on the performance of most drilling fluids.
A Probabilistic Integration of Well Log, Geological Information, 3D/4D Seismic and Production Data: Application to the Oseberg Field
Authors: Castro Scarlet , Caers Jef , Otterlei Cecilie , Andersen Trond , Høye Trond , Gomel Perrine 
Published: December 2007

Abstract
The ultimate goal of reservoir modeling is to obtain a model of the reservoir that is able to predict future flow performance. Achieving this challenging goal requires the model to honor all available static (well log, geological information and 3D seismic) and dynamic (4D seismic and production) data. This paper introduces a general methodology and workflow for reservoir modeling that integrates data from multiple and diverse sources, using a probabilistic approach addressing the possible inconsistency and/or redundancy between various data sources.
The workflow is evaluated in the Oseberg Field, located in the Norwegian sector of the North Sea, 140 Km west of Bergen. The focus of this study is the Upper Ness Formation in the Alpha North structural segment of the field. The main contribution of this paper is the inclusion of 4D seismic data, which has previously not been accounted for within this workflow.
The reservoir modeling workflow applied to this case study helped modeling the spatial distribution of the channel facies using a multiple-point geostatistical technique while honoring all available data and explicitly accounting for data redundancy.
Guidelines for Shale Inhibition During Openhole Gravel Packing With Water-Based Fluids
Authors: Shenoy S. , Gilmore T. , Twynam A. J. , Patel A. , Mason S. , Kubala G. , Vidick B. , Parlar M. 
Published: December 2007

Abstract
Many of the problems associated with the use of water based fluids in drilling and completion operations are caused by incompatibilities between the fluids and the shales. Such incompatibilities may result in washouts, increased drilling costs (solids handling, rig time, dilution fluids), shale sloughing during the drilling operation and after displacements to completion fluids or during gravel packing. One of the most important factors leading to an undesired result (either a premature screenout, thus a potential sand control failure, or a higher skin) in water-packing of open holes is the presence of reactive shales in the interval to be gravel packed.
Although there is a substantial amount of literature on shale inhibition with water-based drilling fluids, the importance of shale inhibition and the problems associated with shale reactivity during gravel packing remain largely unexplored. Furthermore, shale inhibitor selection often relies purely on a comparison of the results from bottle roll tests using shale samples in candidate fluid/inhibitor pairs (drilling or completion fluid) and on tests measuring degree of shale swelling. While these tests are highly functional, they can only provide information on the relative performance of fluids, and their relevance to gravel packing is questionable, as these tests do not simulate the conditions experienced during such treatments.
This paper presents guidelines on selection methodology of shale inhibitors for use in gravel packing applications based on the data available in our respective companies, including a comparison of results from conventional bottle roll tests to those from flow through predrilled holes in shale core samples. Recommendations are made depending on brine type and density, type of shale, temperature, fluid exposure history, as well as environmental considerations.
Transport of Proppant in Hydraulic Fractures
Authors: Clark P. E. 
Published: December 2007

Abstract
Prediction of proppant transport is important in both treatment design and post-treatment analysis. Recently, there has been a resurgence of interest in proppant transport as evidenced by the number of papers presented at SPE meetings. There are a number of factors that have been overlooked in these papers that we believe are of primary importance. This paper summarizes the work that has been done in the area of proppant transport in settling and non-settling fluids. We also present the results of analyzing convection in turbulent flow fracturing treatments.
Dynamics of Vertical Displacement in Porous Media Associated With CO2 Sequestration
Authors: Riaz A. , Tchelepi H. A. 
Published: December 2007

Abstract
The problem of CO2 sequestration in geologic formations is analyzed from a fundamental perspective. The mechanisms of trapping, dissolution and chemical reactions are not accounted for in order to clearly understand the first order behavior of the system. The analysis is concerned with the post injection period when the CO2 plume rises due to buoyancy. Characteristics of the plume for a one-dimensional problem show that a pair of shocks moving in opposite directions is produced at the top end. The downward moving shock interacts with the bottom end of the plume resulting in a decrease in the maximum value of the CO2 saturation. High accuracy numerical simulations are employed to understand the two-dimensional mechanisms of plume evolution in terms of the viscosity ratio and the capillary number. Two-dimensional results show that the plume rises to significantly lower height, in shorter times, as compared to the 1-D problem. This behavior is governed by the two-dimensional velocity field around the plume that additionally leads to spanwise wave interactions and results in a faster decrease of the maximum CO2 saturation. The initial dimensions of the plume have a strong influence on the time scales of the wave interactions. The maximum upward velocity that is generated due to buoyancy is closely related to the maximum saturation and decays rapidly to very small values with a decrease in saturation. In the case where the viscosity of CO2 is a tenth of the viscosity of the surrounding fluid, the plume rises up about 500 m in 700 yrs. Our results provide an upper bound on the maximum rise distance and the sequestration time for the problem involving trapping and dissolution. Comparison with experimental results show that the buoyancy velocity obtained from our results is of the same order as observed in the experiments.
Gas Sorption and Transport in Poroelastic Coals
Authors: Yi Jun , Akkutlu I. Yucel , Deutsch Clayton V. 
Published: December 2007

Abstract
In this paper, natural gas sorption and transient diffusion processes are described within coals exhibiting bimodal (macro- and micro-) pore structure on space-time continuum. Single-component gas is distributed in the microporous solid at adsorbed and dissolved states and in the macropores as free gas. The coal matrix is poroelastic, namely, its solid material manifests swelling and shrinkage effects due to the sorption phenomena under effective overburden stress. Gas transport is Fickian in nature and described by molecular and surface diffusion processes simultaneously taking place in the macro- and micropores, respectively. A free gas concentration-dependent apparent diffusion coefficient is explicitly derived. Initial/boundary value problems are constructed considering the cases of gas uptake by and release from the coal. Consequently, influences of sorption phenomena on solid/macropore volumes and on the overall gas transport are numerically investigated using a finite difference approach. It is found that transport is primarily hindered by equilibrium sorption and takes place at a rate significantly less (typically 1-10 per cent) than that in the macropores only. Macroporosity variations are non-uniform in space and time. These mainly relate to availability of the sorbed gas in microporous solid; thus, the swelling and shrinkage effects are closely associated with the affinity of solid material to the gas component. Only in gas-coal systems with large sorption capacity the solid material is observed to shrink during the gas release and swell as the gas is sorbed by the coal. The estimated macropore volume changes could be as high as ±10 percent, although their effect on the overall gas transport is negligible.
Pioneering Advanced Directional Drilling Technologies Overcome Challenges of S and J Type Wells in North America
Authors: Janwadkar S. , Fortenberry D. , Dawkins B. , Kramer M. , Kurella M. , Welch B. , Reich M. 
Published: December 2007

Abstract
Typically S/J type directional land wells of North America utilize steerable downhole motors. This selection has some limitations: trips to adjust AKO for build/tangent/drop sections, potentially less than optimal hole quality from string rotation, possible drillstring/BHA/casing wear, potential hole enlargements requiring increased cement volumes and high torque/drag due to wellbore tortuosity. Closely spaced wells require precise control of wellpath to prevent collision. Multiple corrections to wellpath may increase wellbore tortuosity. Rotary steerable systems (RSS) requiring rotation of drill string are typically cost prohibitive for this application/environment.
To overcome these challenges research, field testing and ten years of experience gained with other rotating/non-rotating rib steering systems has culminated in the development of a new state-of-the-art directional drilling system. The system, specifically designed for low inclination 3-D wellbores, utilizes an automated rib-steering closed loop system with a non-rotating drill string. Since the introduction of this innovative/sophisticated system many wells have been drilled in North America with build/drop of 3°/100 ft. Vertical/build/tangent and drop sections can be drilled without tripping. Tangent section inclination remained within 0.2°. Wellpath corrections were made while drilling by system's automatic closed loop control. The new system has reduced drilling/completion time, minimized hole enlargements, reduced torque/drag to help deliver smooth high quality wellbores and increased efficiency of cementing operations. This has allowed the operator to log and set tubulars easily and quickly, leading to early production. The innovative system has potential applications in many similar areas of the world to drill simple/complex S/J type wells without string rotation.
Low-inclination wells can be drilled with precision and efficiency due to the closed loop's constant control over wellpath, and the ability to drill long sections without tripping for BHA changes.
Use of Horizontal Well Image Tools To Optimize Barnett Shale Reservoir Exploitation
Authors: Waters G. , Heinze J. , Jackson R. , Ketter A. , Daniels J. , Bentley D. 
Published: December 2007

Abstract
Horizontal wells represent a growing percentage of the drilling activity in low permeability reservoirs within the United States. With effective stimulation techniques, these wells have demonstrated favorable economics compared to vertical wells in the same reservoir due to the much larger hydraulic fracture surface area that is created.
In order to achieve optimum horizontal well stimulation, the lateral section must be characterized and the perforation placement customized to account for reservoir changes along the wellbore. In most cases evaluation is limited to a gamma ray measurement while-drilling (MWD) tool and, periodically, mud log. While these tools can identify significant structural changes and hydrocarbon shows along the lateral, they provide little stratigraphic information, no natural fracture information, and no stress information.
One log evaluation tool that is being used more frequently in horizontal wells is the formation imager. It produces electrical images of the borehole that provide detailed structural information such as faulting and natural fracturing. The images can also be used to estimate the stress state along the lateral via the presence and orientation, or absence, of drilling induced fractures. With this information important completion decisions can be made such as: lateral isolation need, stimulation staging requirements, perforation cluster design and spacing. Images can also identify offset well hydraulic fractures when they are intersected. This too can drive perforating and completion strategies, as well as future infill well placement.
This paper describes how formation images have been used to implement changes to the completion process in horizontal Barnett shale wells. Stimulation staging and perforation placement strategies now utilize this information. In addition, actual stimulation pressure responses and microseismic activity are compared to those predicted from image logs. Infill drilling strategies, taking into account the location of offset hydraulic fractures, are reviewed as well.