bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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 >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

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

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

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

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

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

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

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

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

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.
The Pressure Derivative Revisited—Improved Formulations and Applications
Authors: Hosseinpour-Zonoozi N. , Ilk D. , Blasingame T. A.
Published: December 2007

The proposed work provides a new definition of the pressure-derivative function [i.e., the β-derivative function, Δpβd(t)], which is defined as: Δpβd(t)=dln(Δp)dln(t)=1ΔptdΔpdt=Δpd(t)Δp

(Δpd(t) is the "Bourdet" well testing derivative)

This formulation is based on the "power-law" concept (i.e., the derivative of the logarithm of pressure drop with respect to the logarithm of time) — this is not a trivial definition, but rather a definition that provides a unique characterization of "power-law" flow regimes.

The "power-law" flow regimes uniquely defined by the Δpβd(t) function are: [i.e., a constant Δpβd(t) behavior] CaseΔpβd(t)• Wellbore storage domination:1• Reservoir boundaries:— Closed reservoir (circle, rectangle, etc.).1— 2-Parallel faults (large time).1/2— 3-Perpendicular faults (large time).1/2• Fractured wells:— Infinite conductivity vertical fracture.1/2— Finite conductivity vertical fracture.1/4• Horizontal wells:— Formation linear flow.1/2

In addition, the Δpβd(t) function provides unique characteristic responses for cases of dual porosity (naturally-fractured) reservoirs.

The Δpβd(t) function represents a new application of the traditional pressure derivative function, the "power-law" differentia-tion method (i.e., computing the d ln(Δp)/d ln(t) derivative) pro-vides an accurate and consistent mechanism for computing the primary pressure derivative (i.e., the Cartesian derivative, dΔp/dt) as well as the "Bourdet" well testing derivative [i.e., the "semilog" derivative, Δpd(t)=dΔp/d ln(t)]. The Cartesian and semilog derivatives can be extracted directly from the power-law derivative (and vice-versa) using the definition given above.

Objectives

The following objectives are proposed for this work:
Production Data Analysis of Horizontal CBM Wells in Arkoma Basin
Authors: Mutalik P. N. , Magness W. D.
Published: December 2007

Since 2001, Williams Production Mid-Continent Company has drilled over 200 horizontal wells in the Hartshorne Coal in the Arkoma Basin in southeastern Oklahoma. The Arkoma basin is an elongate sedimentary basin extending from east-central Oklahoma into Arkansas (Figure 1). The primary zones producing CBM gas in the Arkoma Basin are the Hartshorne sand, and, the Upper Hartshorne Coals, which coalesce into one bed towards the north, and, are the most actively explored gas producing reservoir in the western Arkoma basin.

The Hartshorne Coal is a member of the Pennsylvanian Hartshorne Formation, which is a part of the Krebs Group of the Desmoinesian Series (Figure 2). The coals range from high-volatile bituminous to low-volatile bituminous in rank.

The Hartshorne Coal encompasses a large area in Haskell, Pittsburg, LeFlore, and, McIntosh counties, and, ranges from 3 ft to 7 ft in thickness. Typical average horizontal drilled length has ranged from 2000 ft to 2500 ft, with the longest well being over 3000 ft. The wells are usually completed with a slotted liner.

Unlike CBM wells in other areas of the United States, Hartshorne coal wells are relatively "dry", and, typically produce gas from the first month, with very little water production. This paper presents examples of using analytical techniques for production forecasting, and, reserves estimation for horizontal CBM wells in the Arkoma basin. The production analysis results were integrated with core data, and, material balance calculations, and, indicate recovery factors ranging from 50% to 80% for the Hartshorne CBM wells. The paper also provides a comparison of the performance of horizontal and vertical CBM wells in the basin.

In addition, pressure buildup tests were conducted on over 40 horizontal wells, to estimate the reservoir pressure, and, to calculate permeability and skin factor. The paper presents two examples of pressure buildup analysis for Arkoma horizontal CBM wells. The PBU analysis indicated effective permeability in coal of the order of 30 md, which is attributed due to the significant cleating of the Hartshorne coal in the area. The paper includes guidelines for drilling horizontal wells for exploitation of Hartshorne CBM.
Explicit Deconvolution of Wellbore Storage Distorted Well Test Data
Authors: Bahabanian O. , Ilk D. , Hosseinpour-Zonoozi N. , Blasingame T. A.
Published: December 2007

The analysis/interpretation of wellbore storage distorted pressure transient test data remains one of the most significant challenges in well test analysis. Deconvolution (i.e. , the "conversion" of a variable-rate distorted pressure profile into the pressure profile for an equivalent constant rate production sequence) has been in limited use as a "conversion" mechanism for the last 25 years. Unfortunately, standard deconvolution techniques require accu-rate measurements of flowrate and pressure — at downhole (or sandface) conditions. While accurate pressure measurements are commonplace, the measurement of sandface flowrates is rare, essentially non- existent in practice.

As such, the "deconvolution" of wellbore storage distorted pres-sure test data is problematic — in theory, this process is possible, but in practice, without accurate measurements of flowrates, this process can not be employed. In this work we provide explicit (direct) deconvolution of wellbore storage distorted pressure test data using only those pressure data.

The value of this work is that we provide explicit tools for the analysis of wellbore storage distorted pressure data — specifi- cally, we utilize the following techniques: — Russell method (1965) (very approximate approach).— "Beta" deconvolution (1950s and 1980s).— "Material Balance" deconvolution (1990s).

Each method has been validated using both synthetic data and literature field cases and each method should be considered valid for practical applications (the Russell method was not used).

Our primary technical contribution in this work is the adaptation of various deconvolution methods for the explicit analysis of an arbitrary set of pressure transient test data which are distorted by wellbore storage — without the requirement of having measured sandface flowrates.
Rate Allocation Using Permanent Downhole Pressures
Authors: McCracken M. , Chorneyko D.
Published: December 2007

A common industry practice is to commingle production, either downhole or at the surface. Where multiple layers are present in a reservoir, the most economical development plans often involve commingling the production of all the layers. Commingling production is also cost effective in multiple well scenarios such as on a platform. In these situations, it is challenging to determine the individual flow rates from each layer or well. One operating practice is to isolate each layer or well and determine what fraction of the total production can be attributed to each entity. This fraction is then used to allocate production until individual entity rates can be measured again. Rate allocation methods are often required by regulatory agencies and can require expensive well interventions in terms of delayed production and complex completions such as ‘smart’ wells.

Today, many wells are instrumented with permanent downhole pressure gauges which are employed for performance prediction, production optimization, and other reservoir management tasks. In this paper, the use of downhole pressure data is extended to rate allocation. In terms of Darcy's Law, there is a physical link between pressure gradients and flow rates. ExxonMobil has developed a methodology to calculate bottomhole flow rates for each layer or well based on total production and the bottomhole pressure for each layer or well. This paper describes the issues involved, outlines the workflow to address the allocation, specifies the calculations involved, and uses two field examples to illustrate the method. This method shows promise for more accurately allocating production and reducing the required number of well interventions.
Field Experience in Multiphase Gas-Well Testing: The Benefit of the Combination of Venturi and Gamma Ray Fraction Meter
Authors: Pinguet B. G. , Roux G. , Hopman N.
Published: December 2007

Using multiphase flowmeters in field operations has now become a widely accepted practice especially in the range of Gas Volume Fraction (GVF) of 0 to 85%. There is still some doubt about the performance of this type of device especially in the High (92-96%) or Very High GVF (96-98%) ranges. Most of the purchasers put a cut off in the GVF range of 85- 92% following the type of technology. These criteria are often based on past experience or special cases, which could be several years old. A split in terms of naming is even commonly accepted in the multiphase business between Multiphase Flow Meter and Wet Gas Meter.

With the recent dedicated Gas Mode developed by Schlumberger, it is now possible to test both gas and oil wells with the same hardware. The focus put in the past few years on a combination of robust and simple measurements (Venturi and gamma ray) in multiphase flow-metering solutions for any type of well based on the advantages and benefits of the industry recognized Vx* Technology.

In this paper, we will review the benefit of the combination of Venturi and gamma ray fraction meter and its application to gas well testing.

Today, the use of the entire information of a gamma ray spectrum gamma ray (more than 2 rays) allows a real-time or an a posteriori quality control and improvement of the overall performance of the meter in any type of conditions. This statement will be presented through a campaign of tests done in South America. First of all, we will show how the entire information of a gamma ray spectrum permits a quality control in real time, and allows tracking of fluid composition change over time. Then we will focus on high producing gas wells clean-up that have been successfully tested using the Vx technology in Gas Mode in 2005. Exceptional results against conventional test separator have been presented in previous paper (Ref [10]) with a maximum error of 2-3% for the gas.

The current paper will also put a special emphasis on the salinity change.
Flow-Assurance Aspects of Subsea Systems Design for Production of Waxy Crude Oils
Authors: Alboudwarej H. , Huo Z. , Kempton E.
Published: December 2007

Development of deep offshore fields is costly. As such, accurate information is required before a decision can be made on the feasibility of prospect development. Such sets of information include the reservoir fluid characterization and flow assurance data. The subject of this paper is to demonstrate the importance of accurate and representative fluid characterization and resulting flow assurance data on optimum facility and production method design for development of offshore fields.

In this study, fluid characteristics and flow assurance aspects of a live waxy crude oil from offshore West Africa is investigated. Experimental work included determination of the wax appearance temperature (WAT) and rheological studies which included pour point, gel strength, and shear-dependent viscosity measurements under both dead and live oil conditions. The wax deposition tendency of the dead crude oil was also investigated. The experimental data were used for a case study to demonstrate the effect of live oil data versus dead oil data on the subsea system design and operating procedures.

The case study indicated if dead oil data was utilized, the subsea system design and operating procedures would be considerably more conservative than if live oil data was the basis of the design. For a marginal field, these differences could be the difference between an economical field and an abandoned field.
Nonlinear Simulation of Thermo-Viscous Fingering in Nonisothermal Miscible Displacements in Porous Media
Authors: Islam M. N. , Azaiez J.
Published: December 2007

Full nonlinear simulation of the thermo-viscous flow is carried out to study the thermo-viscous fingering in non-isothermal miscible displacements in two-dimensional rectilinear porous media. The problem is formulated using momentum balance equation in the form of Darcy's law, and volume-averaged mass and energy balance equations in the form of convective-diffusion equations. Exponential dependence of viscosity on concentration and temperature is used. With the use of vorticity-streamfunction formulation and periodic boundary conditions, the coupled system of nonlinear equations is solved conveniently using highly accurate pseudo-spectral method. The transient development of thermo-viscous instability is studied for different values of solutal (PeC) and thermal (PeT) Peclet numbers, Lewis number (Le) and the parameters representing the concentration (βC) and temperature (βT) dependence of viscosity. In Hele-Shaw flow, the effects of βC and βT are found to be additive when Le is unity, while at smaller values of Le the frontal instability is further enhanced. At practically large values of Le, the fluid and the thermal fronts evolve differently, with the fluid front being more unstable. The reduction in instability on the thermal front is found to be due to the enhancement of the thermal dispersion in such flow. Finally, it has been noticed that at large values of Le, the instability in the thermo-viscous flow is dominated by the viscosity contrast due to the variation in concentration across the fluid front, which was also reported in earlier literature.
Uinta Basin Single-Well Model To Optimize Tight Gas Completions
Authors: Cherian B. , Aly A. , Denoo S. , Maschio L. , Sobernheim D. , Longwell J.
Published: December 2007

In this paper, we will present an integrated single well modeling (SWM) technique to predict reservoir and completion performance for a Uinta basin development program. This technique has proven to be vital in the economic success of wells in the Uinta Basin. The integrated SWM involves the development of a petrophysical and a mechanical stress model calibrated from offset nearby wells to match well production and fracturing treatments response.

The SWM is coupled with the development of NPV optimization models for each well. Tools for the validation of the SWM such as production logs, pressure measurements, and formation micro-imager (FMI) have not only been crucial in model validation, but also in order to: Evaluate production contributions based on backpressureEvaluate drainage area (from multiple production logs)Understand geological setting and production mechanismDetect scaling problems and optimize treatment solutionsUnderstand limited entryIdentify water producing zonesDevelop commingling production strategy

Since a typical completion in the Uinta Basin may contain multiple producing sands (as many as 30), optimizing the completion strategy may be a challenging task. Completions are designed to optimize the production from each stimulation stage. This is achieved by calibrating the pre-stimulation injection tests on these stages using theoretical fracturing models such as pseudo-3D (P3D). Pressure history matching of fracturing data and production data provides the feedback information necessary to validate the models and improve predictability, thus improving the quality of decisions made subsequently. This process is continuous and models are updated or changed according to the geological and petrophysical setting.

After the wells are completed, the use of production logs in stacked pay reservoirs enables the use of rate-&-pressure transient analysis and history matching techniques to evaluate fracture and reservoir properties. The use of these tools early in the drilling program has resulted in changes to completion and production strategies that have resulted in significant cost saving via modifications to fluid technology, proppant selection, proppant flowback control methods, commingling strategies, scale inhibition and drilling locations. Over all, the application of appropriate evaluation tools based on geological setting and appropriate information gathering has resulted in production increases of up to 30% above the previous baseline, with significant improvement in well economics.
Automatic Concurrent Water Collection (CWC) System for Unloading Gas Wells
Authors: Khoshnevis B. , Rastegar Moghadam R. , Ershaghi I. , Larbi K. , Villagran V.
Published: December 2007

Several methods for unloading water from gas wells have been used in the industry. These methods commonly have a combination of the following characteristics: a) they use external energy, b) they use consumables, and c) they restrict gas production. This paper presents a new approach to water unloading that does not restrict or interrupt gas production, can operate without external energy, and uses no consumables. Physical and software simulators have been developed to demonstrate the feasibility of the new approach and to configure the approach for various well characteristics.
Consistent Downscaling of Seismic Inversions to Cornerpoint Flow Models
Authors: Kalla Subhash , White Christopher D. , Gunning James G. , Glinsky Michael E.
Published: December 2007

Reservoir simulation models are constructed from sparse well data, dense seismic data, and using geologic concepts to constrain stratigraphy and property variations. Because of the sparseness of well data, stochastically inverted seismic data offer important constraints on reservoir geometry and average properties. Although seismic data are densely distributed, they are uninformative about meter-scale features. Conversely, well data reveal fine-scale features but cannot specify intrawell geometry. To build a consistent model, conceptual stacking and facies models must be constrained by well and seismic data. Stochastic ensembles of geomodels are used to capture variability associated with seismic downscaling, lateral variability and conceptual models. The resulting geomodels must be gridded for flow simulation using methods that describe stratal architecture flexibly and efficiently.

In this paper, geomodels integrate stochastic seismic inversion results (for means and variances of "packages" of meter-scale beds), geologic modeling (for a framework and priors), rock physics (to relate seismic to flow properties), and geostatistics (for spatially correlated variability). These elements are combined in a Bayesian framework. The proposed workflow produces models with plausible bedding geometries, where each geomodel agrees with seismic data to the level consistent with the signal-to-noise ratio of the inversion. An ensemble of subseismic models estimates the means and variances of properties throughout the flow simulation grid.

Grid geometries with possible pinchouts can be simulated using auxiliary variables in a Markov Chain Monte Carlo (MCMC) method. Efficient implementations of this method require a posterior covariance matrix for layer thicknesses. Under assumptions that are not too restrictive, the inverse of the posterior covariance matrix can be approximated as a Toeplitz matrix, which makes the MCMC calculations efficient. The proposed method is validated and examined using two-layer examples. Convergence is demonstrated for a synthetic threedimensional, 10,000 trace, 10 layer cornerpoint model. Performance is acceptable (305 s on a 2 GHz Pentium-M processor).

The Bayesian framework introduces plausible subseismic features into flow models, whilst avoiding overconstraining to seismic data, well data, or the conceptual geologic model. The methods outlined in this paper for honoring probabilistic constraints on total thickness are general, and need not be confined to thickness data obtained from seismic inversion: any spatially dense estimates of total thickness and its variance can be used, or the truncated geostatistical model could also be used without any dense constraints.
Stimulation in Asia Pacific Region—Challenges and Opportunities
Authors: Jin L. , Seah M.
Published: December 2007

Oil and gas assets in Shell Asia Pacific region formulate challenges and opportunities for improving well productivity through stimulation. Major factors limiting the activity in the past include: Various types of reservoirsMixed success rateOperational difficultiesCost structure: coil tubing cost overruns the overall stimulation costWeather conditions.

Stimulation activities have been picked up since 2004 with encouraging successes. Among them are successful hydraulic fracture stimulation in STOS and sandstone matrix acid stimulation campaigns in Brunei and Malaysia. Recently, stimulation in carbonate gas reservoirs brought new successes.

This paper discusses what have been done to identify and capture opportunities through collaborated efforts. Best practices and learnings leading to the success will be shared.

Some of the high lights of the practices include: Opportunity identification and detailed designDetailed well-by-well review for first round candidate selection.Fundamental data collection is vital. A data management system allows quick access to well production history data.Design tool (software) for final candidate selection, fluid system selection, and job design.QA/QC and compatibility tests aiming to obtain high success rate.Combine equipment (self-raising rig and barge) with pumping procedure (coiled tubing and bull-heading) to best-fit individual well condition.Close cooperation (Well services, Production technologists, Service providers, etc.) during implementation.Game change in acid stimulating carbonate horizontal gas wells.

Hydraulic fracturing in STOS has significantly improved gas production. Sandstone matrix acidizing campaigns in 2004 brought 9000 boepd of gain in assets in Brunei and Malaysia with high success rate (no failure was recorded).

Confidence level of stimulation in Shell Asia Pacific region has been elevated. Lessons learnt and best practices established will be passed to future campaign. Stimulation is still a good means for increasing well productivity to get more oil at this high oil price time, but it has to be carried our properly.

Although some success was achieved, current infrastructure for stimulation in the region still needs to be improved.
Seismically Driven Reservoir Characterization Using an Innovative Integrated Approach: Syd Arne Field
Authors: Christensen S. A. , Dalgaard T. E. , Rosendal A. , Christensen J. W. , Robinson G. , Zellou A. M. , Royer T.
Published: December 2007

This paper presents an innovative integrated workflow applied to the characterization of a fractured chalk reservoir in the Danish North Sea. The methodology uses simultaneous integration of geophysical, geological and engineering data to produce an improved reservoir description. Integrating dynamic flow data with the geophysical and geologic information in 3D, reservoir properties porosity and effective permeability are generated using artificial intelligence tools. The strength of this technique lies in the fact that property modeling is not constrained to match upscaled well data and consequently these data serve to validate the outcome.

This workflow builds upon a methodology that has been used successfully for the characterization of fracture distribution. The technique has been extended to include the generation of seismically derived models of porosity and matrix permeability.The objective of the approach is to improve the ability to capture the heterogeneity of key reservoir properties, and thus use the resulting reservoir model to both provide improved predictive ability and identify previously undiscovered development opportunities. The application and outcome of this integrated workflow to the Syd Arne field is presented in this paper.
An Analytical Bottomwaterdrive Aquifer Model for Material Balance Analysis
Authors: Yildiz T. , Khosravi A.
Published: December 2007

In this study, we present a new analytical model to predict water influx from finite bottomwaterdrive aquifers (BWDAs). The new model can be used for aquifer representation in reservoir simulators and material balance analysis. The new model is computationally fast. The model has been verified against the results from the Coats and Allard-Chen models. Using the new model, we compare the cumulative water influx from BWD and edgewaterdrive (EWD) aquifers.

In the second part, we couple the new aquifer model with the material balance equation (MBE) and demonstrate its use in reserve estimate. Production data from a bottomwaterdrive (BWD) oil reservoir simulated by Allard and Chen is analyzed. We conducted a McEwen analysis to predict the reserves.
Numerical Modeling of Diffusion in Fractured Media for Gas Injection and Recycling Schemes
Authors: Hoteit H. , Firoozabadi A.
Published: December 2007

Diffusion in fractured reservoirs, unlike in unfractured reservoirs, can affect significantly the efficiency of gas injection in oil reservoirs and recycling in gas condensate reservoirs. The physical diffusion, similar to gravity, results in the change of the path of the injected gas species from the fractures to the matrix, giving rise to late breakthrough. In this work, we present, for the first time, a consistent model to incorporate physical diffusion of multicomponent mixtures for gas injection schemes in fractured reservoirs. The multicomponent diffusion flux is related to multicomponent diffusion coefficients, which are temperature, pressure and composition dependent. These coefficients are calculated from a model based on irreversible thermodynamics. Current simulation models of fractured reservoirs that include diffusion are based on inconsistent models of gas to liquid diffusion at the fracture-matrix interface. We avoid this deficiency by assuming that the gas and liquid phases are in equilibrium at the interface. The concept of crossflow equilibrium (that is, vertical equilibrium) is invoked in our model to avoid the use of transfer functions. In this work, we use the combined discontinuous Galerkin and mixed methods to calculate fluxes accurately and to have low numerical dispersion to study physical diffusion. Four examples are presented. In one of the examples, a field scale study is performed to investigate gas injection in a fractured reservoir away from miscibility pressure and close to miscibility pressure. Results show a significant effect of diffusion on recovery performance away from miscibility pressure. In another example, recycling in a fractured gas condensate reservoir is presented to demonstrate that diffusion has a significant effect on condensate recovery.
Education for the Real World: Equipping Petroleum Engineers To Manage Uncertainty
Authors: Bratvold R. B. , Begg S. H.
Published: December 2007

An accurate assessment of uncertainty is now seen as a necessary starting point from which to make decisions that will create value and/or mitigate loss in value (risk). As such, uncertainty analysis drives the decisions that are made, rather than just being an add-on, or afterthought, piece of "risk analysis". This impacts the way it should be taught - as an integral part of (almost) all technical courses.

Unfortunately, university training in petroleum engineering does not reflect this required focus on uncertainty understanding and management.

In this paper we discuss the current state of uncertainty management in petroleum engineering curricula. We then propose some essential elements that should be a part every petroleum engineer's educational background and discuss ways to implement these elements into the curriculum without reducing the essential understanding that graduates must have for basic petroleum engineering topics.