bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Acid-Fracturing in Adverse Conditions: Lessons Learnt and Integrated Evaluation in the Kharyaga Field
Authors: Poitrenaud H. , Ferrand P. , Pouget P. , Manière J.
Published: December 2007

The Kharyaga field is located in Timan-Petchora region of Northern Russia, 60 km North of the Arctic Polar Circle. The field is producing principally from a Devonian age carbonate reservoir, this limestone formation having an average porosity of 8 to 12% and permeabilities ranging from 1 to 200 mD. The wells are completed as cased-hole, with a 7inch liner through the reservoir section. The perforated intervals range from 30 to 80 m in length and the wells were traditionally matrix-acid stimulated following perforation. The wells produced initially unassisted then later on, a work-over campaign was launched in order to equip the well with electrical submersible pumps (ESP).

Work-over operations were taken as an opportunity to re-stimulate lower-performing wells of the field. Several options were considered for this purpose from mechanically-diverted acid squeeze to propped hydraulic-fracturing or acid-fracturing this later option being ultimately selected. However, the rather adverse conditions existing both downhole and at surface rendered such an operation quite challenging. In the first place, the tectonically active nature of this region (West of Ural) led to anticipate significantly high fracturing gradients and difficulties to initiate a fracturing regime. Secondly, the weather conditions, with surface temperatures ranging from +20°C in summer to -50°C in winter and logistical issues necessitated adjustments to the fracturing fluids and job design. Finally other factors such as a high tendency of the Khariaga crude to precipitate wax, the presence of H2S or the flow-back through the ESP called for additional precautions.

In this paper we will show that despite these rather adverse conditions successful acid-fracturing treatments can be implemented in this region; we will discuss some of the key parameters that helped base the choice of treatment type and we will describe the lessons learnt during such treatments.

In addition, as the data-set available for this acid-fracturing treatment is unusually comprehensive with image logs, production profiles, pre and post-frac thermal logs, bottom-hole gauges and extended post-frac decline, an integrated evaluation of the treatment will be proposed.
A New Experimental Technique for Studying Gas Mass Transfer in the Crude Oil by Analysis of the Measured Dynamic and Equilibrium Interfacial Tensions
Authors: Yang D. , Gu Y.
Published: December 2007

This paper presents a new experimental technique and its computational scheme for studying gas mass transfer in the crude oil at high pressures and elevated temperatures by analysis of the measured dynamic and equilibrium interfacial tensions. In the experiment, a see-through windowed high-pressure cell is prefilled with a test gas at a prespecified pressure and a constant temperature. Then, a crude oil sample is introduced by using a specially designed syringe delivery system to form a pendant oil drop inside the pressure cell. Due to the dissolution of the gas into the pendant oil drop, the dynamic interfacial tension between the test gas and the crude oil keeps reducing and eventually reaches its equilibrium value when the saturation state is achieved. The sequential digital images of the dynamic pendant oil drop are acquired and analyzed by applying computer-aided image acquisition and processing techniques to measure the dynamic interfacial tensions at different times. Theoretically, a mathematical mass transfer model is formulated to describe the diffusion process of the gas in the pendant oil drop. This model is numerically solved by applying the semi-discrete Galerkin finite element method to obtain the transient gas concentration distribution inside the pendant oil drop. With a pre-determined calibration curve of the equilibrium interfacial tension versus the equilibrium gas concentration in the crude oil, the dynamic interfacial tension at any time is calculated. The mass transfer Biot number and the gas diffusion coefficient are thus determined by finding the best fit of the theoretically calculated dynamic interfacial tensions to the experimentally measured data. This newly developed experimental technique is applied to measure the mass transfer Biot number, the diffusion coefficient, and the interface mass transfer coefficient of CO2 in a reservoir oil sample at P=0.1~5.0 MPa and T =27°C.
The Use of Well Testing for Evaluation of Connected Reservoir Volume
Authors: Levitan M. M. , Ward M. J. , Boutaud de la Combe J. -L. , Wilson M. R.
Published: December 2007

In its search for new oil and gas reserves the oil industry moves to more and more remote areas of the world and to technically challenging areas of deep water. Development of hydrocarbon resources in these environments is extremely expensive. To be economically viable, the newly discovered fields must be developed and effectively exploited with very few wells. This forces the oil companies to concentrate on high quality reservoirs that yield highly productive wells with large reserves per well. High costs prohibit extensive appraisal activity and drive development decisions based on very few wells. Whilst these limited penetrations are often logged extensively using modern formation evaluation tools, the acquired static data cannot confirm that the wells will drain sufficient reserves. Evaluation of reservoir connectivity over large distances from the well requires relatively long and expensive well tests.

In this paper we review a number of critical points associated with design and execution of such tests. The key here is to ensure that the data acquired during the test will contain sufficient information to draw conclusions about the reservoir connectivity and to estimate the reservoir volume that is in communication with the well. We discuss the well test sequences used for this purpose, the tools and operational aspects of well test execution, the data acquisition, the well test analysis techniques, the accuracy and the degree of uncertainty of test results. We illustrate this application of well testing for reservoir connectivity with several real test examples.
Efficiency of Conversion of Work of Drainage to Surface Energy for Sandstone and Carbonate
Authors: Seth S. , Morrow N. R.
Published: December 2007

The increase in surface energy resulting from drainage of a wetting phase from a porous medium is often equated to the work of displacement determined from the area under its capillary pressure curve. However, capillary pressure versus saturation relationships are not reversible and do not represent quasistatic displacement. The increase in surface energy is less than the work done because of inherent capillary instabilities that are the basic cause of capillary pressure hysteresis. Nevertheless, identification of the area under a capillary pressure curve with thermodynamic work of displacement can be justified by interpreting the curve as a series of alternating isons (reversible displacements) and rheons (spontaneous redistribution at constant saturation). The efficiency of conversion of work to surface energy, Ed, depends on the increase in surface area that accompanies drainage. Surface areas of non-wetting phase/solid and non-wetting phase/wetting phase have been determined through displacement of a colored low-viscosity liquid resin which can be solidified so that thin sections reveal the distribution of phases and surfaces within the pore space of the rock. Two dimensional images obtained from thin sections were analyzed using stereology to obtain estimates of saturations and interfacial areas in three dimensions. For drainage of Berea sandstone to 20% wetting phase saturation, Ed was 36% which was less than one half of the efficiency of 85% for the same range of change in saturation determined previously for random packings of equal spheres. Values of Ed for the tested carbonate were about one half of those for sandstone. The wide variation is explained in terms of a simple pore model that relates Ed to aspect ratio.
An Upscaling Procedure for Constructing Generalized Dual-Porosity/Dual-Permeability Models From Discrete Fracture Characterizations
Authors: Gong B. , Karimi-Fard M. , Durlofsky L. J.
Published: December 2007

The geological complexity of fractured reservoirs requires the use of simplified models for flow simulation. This is often addressed in practice by using flow modeling procedures based on the dual-porosity/dual-permeability concept. However, in most existing approaches, there is not a systematic and quantitative link between the underlying geological model (in this case a discrete fracture model) and the parameters appearing in the flow model.

In this work, a systematic upscaling procedure is presented to construct a generalized dual-porosity/dual-permeability model from detailed discrete fracture characterizations. The technique, referred to as a multiple subregion model, represents an extension of an earlier method that did not account for gravitational effects. The subregions (or subgrid) are constructed for each coarse block using the iso-pressure curves obtained from local pressure solutions of a discrete fracture model over the block. The subregions thus account for the fracture distribution and can represent accurately the matrix-matrix and matrix-fracture transfer. The matrix subregions are connected to matrix in vertically adjacent blocks (as in a dual-permeability model) to capture phase segregation due to gravity. Two-block problems are solved to provide fracture-fracture flow effects. All connections in the coarse scale model are characterized in terms of upscaled transmissibilities, and the resulting coarse model can be used with any connectivity-based reservoir simulator.

The method is applied to simulate 2D and 3D fracture models, with viscous, gravitational and capillary pressure effects, and is shown to provide results in close agreement with the underlying discrete fracture model. Speedups of about a factor of 80 are observed for a complex 3D example.
Minimum Miscibility Pressure Prediction Using Statistical Associating Fluid Theory: Two- and Three-Phase Systems
Authors: Zhao G. -B. , Adidharma H. , Towler B. , Radosz M.
Published: December 2007

Miscible gas flooding is a well-known methodology for enhanced oil recovery. One of the key parameters in the gas flooding is the minimum miscibility pressure (MMP), which is the lowest pressure required to achieve multiple contact miscibility between injected fluid and oil. Among approaches for MMP prediction, analytical method and multiple-mixing-cell model are the most appealing approaches because they are robust and explanatory for complex miscibility process mechanism. These two approaches are usually coupled with empirical equations of state (EOS). Our goal is to develop a multiple-mixing-cell approach coupled with Statistical Associating Fluid Theory (SAFT) for predicting MMP for two- and three-phase systems. The coupling of SAFT EOS to a multiple-mixing-cell approach enables us to study the effects of gases and chemical modifiers.

In this preliminary work, for two-phase systems, we demonstrate that our multiple-mixing-cell model gives the same results as analytical method. For a gas-oil system with nc components, gas injection process leads to nc+1 constant-composition zones and the compositional path of the process, i.e. path in the compositional space representing the total composition, is controlled by nc-1 key equilibrium tie lines, i.e., initial tie line, injection tie line, and nc-3 crossover tie lines. In addition, our approach clearly demonstrates that both gas-oil ratio and fluid mobility do not affect tie-line compositional paths, i.e. compositional paths that lie on the thermodynamic equilibrium tie-lines, but they do affect nc-2 non-tie-line compositional paths. Therefore, both gas-oil ratio and fluid mobility do not affect MMP. In the context of multiplemixing-cell model, this fact has never been explicitly clarified before. The coupling of SAFT EOS to our multiple-mixingcell is also discussed.
The Selection, Application, and Misapplication of Reservoir Analogs for the Estimation of Petroleum Reserves
Authors: Hodgin J. E. , Harrell D. R.
Published: December 2007

This paper contains materials and concepts from both an engineering and geoscience perspective relative to the reliance upon suitable analog reservoirs for some or all of the pertinent reservoir rock and fluid qualities in the estimating of reserves quantities and the classification of such estimates.

The information in the paper is expected to be useful to professional reservoir engineers and geologists in predicting reservoir performance for reserves estimation, reservoir management and other predictive needs. The ultimate choice of the use and application of data from analogous reservoirs is always based upon the judgment of the evaluator but guidelines presented in this paper will assist in providing criteria for the more consistent application of analogs.

All judgment decisions in reservoir evaluation are based upon the evaluator's collective experience in reservoir geology or engineering and are thus subjectively analog based. Little of our collective experience, however, has been gathered in any systematic way where all pertinent reservoir and fluid characteristics have been identified. The pertinent characteristics go far beyond the typical measurements of depth, pressure, temperature, porosity, permeability and oil gravity – as primary parameters – and arguably should include depositional environments, mineralization, trapping mechanism, drive mechanisms, structural stresses, wettability, pore throat sizes and other often unknown or ignored features or descriptive parameters. Equally important is the recognition of the frequent and continuing misunderstanding and erroneous application of analog data, some of which is described in this paper.

The topic is significant because of the continuously growing interest in reliable reserves estimates and economic forecasts by companies, investors, regulators, governments and the public at large and because there are no similar papers available through the SPE library or other readily accessible sources.
Automated Route Finding for Production Flowlines to Minimize Liquid Inventory and Pressure Loss
Authors: Xiao J. J. , Al-Muraikhi A. J. , Qahtani A. M.
Published: December 2007

Conventionally, there is insufficient linkage between the selection of a route for a long production flowline and its hydraulic behavior under multiphase flow. A simplified, yet typical process in selecting and designing a multiphase flowline is as follows. Based on survey data, pipeline engineers pick the route. The selected route is then passed onto production or facility engineers for steady-state and transient flow simulation studies. The results of these studies are subsequently used to design the receiving facilities such as slug catchers and separators. This practice has, in many cases, led to slugging issues at gas plants and premature well shutoff due to high flowline back pressures in hilly terrain oil production lines.

In this paper, we present an integrated methodology and a tool that allows the production flowline path to be determined automatically, and with flow hydraulic behavior considered. The method uses digitized surface elevation data. In the route selection process, any number of surface features of different cost factors can be included such as loose soil, rocky hills, wet land, roads, rivers, existing facilities, non-passable installations, etc. Moreover, hydraulic calculations and economic evaluation can be integrated into the path-finding process to give a best route. This path-finding tool allows engineers to quickly evaluate several options such as 1) the shortest flowline path, 2) the path that gives the minimum total net uphills, 3) the path that gives the minimum net uphills and downhills, 4) the path that gives the minimum liquid inventory, and 5) the path that balances the pipeline cost and pressure loss.
Well Integrity Operations at Prudhoe Bay, Alaska
Authors: Anders J. , Rossberg S. , Dube A. , Engel H. , Andrews D.
Published: December 2007

This paper discusses the well integrity management system used at the Prudhoe Bay field located in Alaska. The focus is on systems and processes implemented to manage the well operations and interventions phase of a well's life. Well integrity is a multi-faceted discipline, spanning a well's life from design to abandonment. The engineering aspects of well integrity have received increasing attention in recent years as public scrutiny and resultant regulatory requirements have evolved. The issue of sustained casing pressure (SCP) on the annulus of a well has also shaped current well integrity practices. There have been several recent Applied Technical Workshops focused on well integrity, demonstrating its increasing importance. However, there is notably little well integrity related literature in the SPE paper library (see references 1-4 for a listing of relevant papers).

The well integrity management system used at Prudhoe Bay has been evolving since field startup in 1977. Extensive experience has resulted in the design and management of systems to ensure safe operations, compliance with industry standards, regulatory agency requirements, internal company policies and incorporating "lessons learned" from local incidents. This paper focuses on the operational and well intervention phases of a wells life and discusses evolution of the well integrity management system. Current operating practices are reviewed using BP's "7 Elements of Well Integrity" categorization. Finally, the data management system used to monitor the well integrity system status is reviewed.
General Transfer Functions for Multiphase Flow
Authors: Lu H. , Di Donato G. , Blunt M. J.
Published: December 2007

We propose a physically-motivated formulation for the matrix-fracture transfer function in dual permeability and dual porosity reservoir simulation. The current Barenblatt-Kazemi1-3 approach uses a Darcy-like flux from matrix to fracture, assuming a quasi steady-state between the two domains. However, this does not correctly represent the average transfer rate in a dynamic displacement. Based on one-dimensional analytical analyses in the literature we find expressions for the transfer rate accounting for both displacement and fluid expansion. The resultant transfer function is a sum of two terms: a saturation-dependent term representing displacement and a pressure-dependent term representing fluid expansion. The expression reduces to the Barenblatt form for single-phase flow at late times, but more accurately captures the pressure-dependence at early times. For displacement we consider both imbibition and gravity drainage processes.

The transfer function is validated through comparison with one-dimensional fine-grid simulations and compared with predictions using the traditional Kazemi et al.3 formulation. We show that our method captures the dynamics of expansion and displacement accurately, giving better predictions than current models, while being numerically more stable.
Selection of an Adequate Completion Type is the Key to Successful Reserves Recovery. Case History of Horizontal Drilling in the Reservoirs with Different Depositional Settings (by the Example of the Sporyshevskoye Oil Field)
Authors: Ryzhov Sergey , Malyshev Vladimir , Kruchkova Tatyana , Zubareva Anna , Vasiliev Andrey , Maslennikova Yulia , Selemenev Sergey , Kolesova Marina
Published: December 2007

The Sporyshevskoye oil field development started in 1995. In 2002 by the time when all the designed vertical wells had been drilled, practically all the reserves of the main reservoirs within the production targets were put into production. There emerged a necessity to develop the oil-water zones and marginal areas, zones with poor reservoir properties and minor reservoirs in order to maintain the production rates.

Application of horizontal drilling allowed achievement of the above tasks. Horizontal completions resulted in not only enhancement of individual well production rates, but also significantly improved the oil recovery. This goal was achieved through optimization of the development system and improved development of oil-water zone reserves and the reserves contained in the zones with poor reservoir properties. The use of the horizontal completion allows development of the reserves, which would have never been possible to produce with vertical wells because of poor economics. Another crucial achievement resulting from horizontal completions was the more efficient use of existing wells. Poor vertical producers were sidetracked; the vertical wells released due to drilling of horizontal boreholes were recompleted; the number of shut-in wells reduced.
Integrated Optimization of Field Development, Planning, and Operation
Authors: Guyaguler B. , Ghorayeb K.
Published: December 2007

Field management (FM) is the simulation workflow through which predictive scenarios are carried out to assist in field development plans, surface facility design/de-bottlenecking, uncertainty/sensitivity analysis and instantaneous/lifetime revenue optimization from a hydrocarbon field. This involves, among others, the usage of reservoir simulators, surface-network simulators, process-modeling simulators, and economics packages.

We present a comprehensive, portable, flexible, and extensible FM framework completely decoupled from surface and subsurface simulators. The framework has a clearly defined interface for simulators and external FM algorithms. Any black-box simulator or algorithm may become a part of the system by simply adhering to the FM interface, which is discussed in this paper.

The FM framework capabilities are demonstrated on several examples involving diversified production strategies and multiple surface/subsurface simulators. One real field case that requires advance/complicated development logic is also presented.
Laboratory and Field Trial Results of Condensate Banking Removal in Retrograde Gas Reservoirs: Case History
Authors: Garzon F. O. , Al-Anazi H. A. , Leal J. A. , Al-Faifi M. G.
Published: December 2007

Gas condensate reservoirs experience significant productivity losses as reservoir pressure goes below the dew point. This productivity loss is related to the liquid dropout in the vicinity of the wellbore and the subsequent decline in gas rate which is associated to the reduction in gas relative permeability. To overcome this problem, gas condensate wells are often fracture stimulated to reduce the drawdown and subsequent formation of the condensate bank around the vicinity of the well. In gas wells that have been fracture stimulated to enhance productivity and to delay the creation of a condensate bank around the wells, the likelihood of developing a condensate bank near the wellbore is high due to lack of pressure support and or lower bottom hole flowing pressure in the well. The necessary lab work was conducted to evaluate the possibility of using filtered diesel to remove condensate banking from gas wells. Extensive core flood tests have been performed on carbonate reservoir cores using diesel, and combination of diesel with surfactants and mutual solvents. Laboratory results clearly indicated that there is a productivity improvement when using filtered diesel in combination with mutual solvent. In addition to this, a field trial to evaluate the benefits of such stimulation treatment has been implemented on a gas well that showed conclusive evidence of condensate banking. Pre and post pressure buildup tests data has been collected to assist in the evaluation process. This paper describes in detail the laboratory work, treatment design, and the field trial results of using such technique to remove condensate banking from gas wells.
Low Porosity Fractured Reservoir Characterization For Exploration and Horizontal Drilling
Authors: Sokolov E. , Makarytchev G. , Troitskaya E. , Tukhtaev R.
Published: December 2007

Yurubcheno-Takhomskaya oil and gas accumulation zone (YTZ) located in the western part of the Siberian platform is known as a really challenging exploration object. The main reservoirs are located in Riphean carbonates made up of single p.u. porosity dolomites. Prospective drilling of the territory demonstrated high heterogeneity of this formation. Prospective wells drilled to this formation tests results vary from 0 to more than 600 m3 oil per day.

The article describes efforts made on a new exploration approach elaboration based on an integral analysis of the structural, seismic and borehole data. First of all, this is seismic profiling on the regular orthogonal grid with the employment of modern seismic techniques and technologies, and also the study of the distribution of fractures in-situ (directly in the location of the deposition) with the integrated use of equipment and technology of formation micro-scanners and dipole sonic tools.

This new approach consists on high-potential zone localization controlled by the disintegrated levee-like stromatolithic constructions, which are more exposed to fractured formation due to high silification in the southern and northern slopes of the Madrinskiy and Irkineevo-Katangskiy rifts respectively. Besides, highly productive may turn out to be the highly fractured streaks and sections, controlled by the regional and zonal fault zones. Such localization of the highly productive sections within the huge oil-and-gas-bearing territory allows hoping for the realization of the opportunity of the recovery of reserves of the entire region by limited number of high flowrate wells with the natural recovery drive.
Formation Evaluation of Horizontal Water Injectors Drilled in Thick Carbonate Reservoirs: Behind-Casing-Analysis and LWD Resistivity Modeling
Authors: Ma S. M. , Al-Hajari A. A , Butt P. , Crary S.
Published: December 2007

Formation evaluation (FE) of horizontal injectors drilled in water swept reservoirs involves different physical understanding of log responses to fluid flow and distribution than that FE of oil producers drilled in dry oil intervals. In reservoirs swept with water, effects of rock electrical anisotropy on logging-while-drilling (LWD) apparent resistivity measurements (attenuation and phase shift) could be significant. These effects need to be considered in resistivity log interpretation. In this study, LWD resistivity modeling work was conducted to study relationships between true formation resistivity and LWD tool responses. In situations where the time-consuming resistivity modeling/inversion is not available, LWD apparent attenuation is found to be more representative to true formation resistivity than the apparent phase shift resistivity, thus can be used in formation water saturation estimation.

An alternative measurement of formation fluid saturation is by pulse neutron (PN) after well completion. New technologies have been developed to characterize formation saturation through casing, i.e., behind-casing-analysis (BCA) which includes PN and casedhole resistivity. Logging long horizontal intervals of BCA services is different from logging vertical wells. First of all, the issue of vertical resolution in horizontal wells is not as critical. Secondly, the gravity effect on the tool orientation is different. Data quality could also be different when logging long intervals of the casedhole resistivity because the tool requires physical contact between the measurement pads and the casing. In this paper, all these issues are summarized. The BCA logs are integrated with results of the LWD modeling and production data while underbalanced drilling to provide more accurate formation evaluation.
Optimized Tubing String Design Modeling for Improved Recovery
Authors: Poe B. D.
Published: December 2007

This paper presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells that produce free liquids in conjunction with the gas. Particularly important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required to continuously transport and unload liquids from the well. Subcritical velocities are often encountered in low productivity gas wells that produce liquids, whether the wellbore liquids are produced directly from the formation and/or condensed from the gas in the wellbore. The produced liquids considered in the analysis can be water and/or liquid hydrocarbons.

This paper presents an optimization technique for determining the most efficient production tubing string setting depth design that will keep the wellbore continuously unloaded of produced liquids, yet result in the maximum gas recovery possible under those conditions. The optimization can be performed for a single completion operation during the productive life of the well, or for a series of periodic well interventions during the productive life of the well for which the tubing string setting depths are selected.

The wellbore liquid-loading mechanism in a sub-critical velocity production system has been considered in the analysis using a mechanistic wellbore outflow model. A commingled reservoir inflow performance model was utilized in the analysis to evaluate the fluid inflow of multilayer gas reservoirs that may produce liquids in conjunction with the gas.
Formulas for Rupture, Necking, and Wrinkling of OCTG Under Combined Loads
Authors: Klever F. J.
Published: December 2007

Advanced well design methods based on risk assessment of actual failure mechanisms require accurate formulas for burst, collapse, yield and fracture. Moreover, these strength formulas should be generalized to account for the combined internal pressure, external pressure and axial load that well tubulars experience.

This paper describes the development of a set of formulas for burst strength, i.e. the failure envelope and the design limit for OCTG under internal over-pressure and any axial tension or axial compression. Phenomena covered are ductile rupture, pipe necking and local pipe wall wrinkling, thus spanning the first and second quadrant in the effective axial load – pressure differential load space.

It is based on a large strain, elastic-plastic, < 3D > formulation of pipe equilibrium, deformation and buckling that has been solved analytically in closed form for the situation of combined loads. The formulas describe features such as a maximum internal pressure load (rupture), a maximum axial tension load (necking) and local buckling of a pipe under axial compression (wrinkling).

Approximate burst strength formulas are presented that together span the entire axial load range and closely match the more complex, exact model predictions.

The joint API/ISO SC5 Work Group 2B tasked with modernizing the API 5C3 property equations has incorporated the burst strength formulas presented in this paper into the new ISO TR 10400 standard1.
Acid Fracturing or Proppant Fracturing in Carbonate Formation? A Rock Mechanic's View
Authors: Abass H. H. , Al-Mulhem A. A. , Alqam M. S. , Mirajuddin K. R.
Published: December 2007

Acid fracturing is performed to improve well productivity in acid-soluble formations such as limestone, dolomite, and chalk. Hydrochloric acid is generally used to create an etched fracture, which is the main mechanism for maintaining the fracture open during the life of a well. Proppant fracturing is an alternative option that has been applied in carbonate formations. In certain areas, proppant fracturing has been used as a standard stimulation method for carbonate formations. There is no quantitative method to provide an answer of whether acid fracturing or proppant fracturing is an appropriate stimulation method for a given carbonate formation.

In proppant fracturing, proppant is used to sustain the effect of the minimum horizontal stress from closing the fracture. In acid fracturing the etched, non-smooth, surface with sufficient roughness should leave open channels upon closing. The effect of elastic, plastic, and creeping deformations in acid fracturing and the proppant crushing and embedment in proppant facturing, on reducing fracture permeability is investigated. The viscous effect, creeping, is a slow displacement that incurred over a long period of time. The creeping effect on fracture closure following an acid fracturing treatment is demonstrated in this paper.

Laboratory experiments have been performed to simulate acid and proppant fracturing treatments. The effect of elastic, plastic and viscoelastic rock behavior on fracture conductivity was studied for acid and proppant fracturing treatments, using full core samples. Comparison of acid vs. proppant fracturing conductivity in carbonate formation is also presented.
A New Hydraulic Fracturing Package Fit for Arctic Conditions Improves Operational Efficiency and Fracture Conductivity and Enhances Production in Western Siberia
Authors: Kirilov V. , Yamilov R. , Lyubin G. , Dessinges M-N. , Parris M. , El Kholy I. , Leugemors E. , Ayala S. , Pessin J-L. , Fu D. , Sock D. , Maniere J. , Butula K. , Mullen K.
Published: December 2007

The extreme weather, the poor road conditions, the use of a wide variety of local river and produced waters, and the time-consuming batch mixing operations of tons of gel prior to the operation make each fracturing job in Siberia a real challenge. In a market where production needs are growing, efficiency and streamlined operations are required to enable a higher utilization rate and maintain execution quality.

This paper introduces a new system where engineered polymer-based fracturing fluid and mixing equipment were integrated. While the conventional fracturing systems employ either batch mixing of gel for hours prior to the operation, or continuous mixing using polymer slurries suspended in hydrocarbon, the solution introduces mixing on-the-fly of all the streams, including the dry polymer, the crosslinker, and the activator streams. This significantly reduces the duration of each treatment. With the utilization of high yielding polymer, the new technology allows a reduction in polymer loading close to 20%, which translates to an increase in proppant pack conductivity of up to 10%, and thus an increase in productivity. The new technology introduces blends, allowing increased simplicity and improved reliability. The enhanced utilization of dry chemicals in an environment of sub-freezing temperatures also contributes to the operational simplicity. The system incorporates a robust chemistry with reduced sensitivity to additive concentrations and improved compatibility with local waters. The system has a broad application temperature range from 37°C to 149°C.

As of today, 143 treatments have been successfully performed in the Priobskoe region of western Siberia with the integrated solution using various fields mixing waters. The duration of treatments has been reduced on average by 8 h, while 100% of the proppant was placed in 88% of the cases. The new fluid system has further allowed a decrease in polymer loading of 17% during the treatments.
The Potential of Multiple Fractured Horizontal Wells in Layered Reservoirs
Authors: Butter Machiel , East Loyd , Kuvshinov Igor
Published: December 2007

Many western Siberia oil fields are being developed/exploited with hydraulically fractured S-shaped wells (vertical through the pay section). Horizontal wells are also used; however, in many of the fields these wells are outperformed by vertical, fractured (VF) wells. The reasons for this often are poor vertical permeability and sub-optimal drilling and completions practices.

To better quantify the potential of an undeveloped area of a western Siberian field, five different well types were evaluated: vertical, vertical-fractured, slanted (85°, crossing multiple layers), horizontal (with a single layer), and multiple-fracture horizontal (MFH) wells. These well types were evaluated using a reservoir simulation model of a sector of the field. The results of this analysis demonstrated that the MFH well completions can outperform the other well types and that they can have a positive impact on the economics of the field development.

With traditional fracturing and completion techniques, where packers or bridge plugs are used to provide zonal isolation, fracturing horizontal wells is a complex operation with substantial risks and is not always economical. New hydrajet-assisted fracturing (HAF) techniques can eliminate many of the problems and reduce the risks. Recent developments in this technology make it simpler to perform the same type of aggressive frac jobs as currently performed in vertical wells, with large proppant volumes and large proppant sizes (12/18-mesh), at multiple selected locations along a lateral wellbore.

To realize the full potential of this type of well, traditional thinking, regulatory barriers, and equipment limitations need to be overcome. This process has started, and some operators are currently planning trial MFH wells to demonstrate their potential.

This paper discusses the potential demonstrated by the study and recent technology developments that will allow the easier placement of multiple fracs in horizontal wellbores. It also highlights the practical aspects that need to be addressed for operators to fully capture the potential.
A Generalized Material Balance Equation for Coalbed Methane Reservoirs
Authors: Ahmed T. , Centilmen A. , Roux B.
Published: December 2007

The objective of this paper is to present three contributions regarding the mathematical development of material-balance-based methods for analyzing unconventional gas reservoirs, particularly coal bed methane ("CBM") reservoirs. These three contributions are:

Contribution 1: A generalized material balance equation ("MBE") that accounts for and incorporates the Langmuir isotherm, initial free gas, water expansion, and formation compaction. This particular form of material balancing can be used to estimate the original gas-in-place and, unlike other methods, does not require an iterative process to solve the equations involved.

Contribution 2: Prudent CBM reservoir management and optimization requires knowledge of reservoir pressure. An iterative method has been developed to predict reservoir pressure throughout the producing life of the reservoir using only initial reservoir pressure, Langmuir isotherm, and cumulative gas production. Use of the proposed method has the potential to significantly reduce operating costs by minimizing the number of pressure surveys.

Contribution 3: A contribution designed to provide an efficient iterative scheme that incorporates the gas-water relative permeability data to predict future performance of the CBM reservoir.

The paper documents the practical applications of the proposed MBE and verifies its accuracy through comparison with results of numerical simulation on several field examples.

The proposed MBE can provide an independent source of validation for numerical simulators and is applicable to any coal which behaves according to the Langmuir isotherm equation. The Method can accurately predict the future production and pressure performance and, hence, it has the potential to significantly reduce operating costs by minimizing the number of pressure surveys required.
Enhancements in PDC Bit Design and Drilling Optimization Tackle Hard Conglomerate Rock Drilling in Northern Mexico
Authors: Rodriguez Carlos Solano , Montejo Carlos , Yam Ricardo , Bustos Oswaldo , Luis Sanchez Jose , Romero Jorge , Rodriguez John
Published: December 2007

This paper discusses the successful application of polycrystalline diamond compact (PDC) bits in drilling a hard conglomerate formation with confined compressive strengths in the range of 20,000 to 40,000 psi. Over 30% savings in drilling cost was achieved through improved penetration rate, extended bit life and reduced bit trips.

Advances in bit design and cutter technology are allowing PDC bits to be used repeatedly in this hard conglomerate interval in northern Mexico's Burgos basin. Previously the exclusive domain of IADC 417 to 537 insert rock bits, the heterogeneous formation contains chert nodules that are too hard for conventional PDC bits, which are subject to cutting structure damage that reduces the rate of penetration (ROP).

A conventional bit program for this formation used a PDC bit to reach the top of the Conglomerada Norma interval, then changed to an insert bit to drill to the base of the conglomerate. A final trip picked up a PDC bit to reach interval TD. This formation is quite common throughout the basin and is found at various depths and thickness in the Cuitlahuac, Torrecillas, Comitas, Fundador and Sigma fields.

Case histories will illustrate successful application of advanced PDC bit designs in conjunction with optimized drilling parameters and bottomhole assemblies, as well as cost savings achieved throughout the course of this drilling campaign. This enhanced technology in conjunction with effective teamwork involving the operator, drilling contractor and bit supplier established field records while reducing drilling expenditures.
Modeling the Effect of Viscosity Ratio on Spontaneous Imbibition
Authors: Fischer H. , Wo S. , Morrow N. R.
Published: December 2007

Spontaneous imbibition data for Berea sandstone cores, that are very strongly wetted by the aqueous phase and initially 100% saturated with mineral oil, are reported for linear, radial, and all-faces-open boundary conditions. Oil viscosities were 4, 63 and 173 cP and aqueous phase viscosities ranged from 1 to 495 cP. Oil/aqueous phase viscosity ratios were varied by over four orders of magnitude (0.01 to 173.1). Near-linear relationships, with slopes close to one half, between the frontal position and imbibition time on a log-log scale were obtained for both linear and radial counter-current flow. Behavior is consistent with near piston-like displacement by the imbibing aqueous phase. The results are analyzed by a new mathematical model that accounts for counter-current spontaneous imbibition with symmetrical flow patterns. The model assumes that saturation and permeabilities to counter-flowing phases behind the front are constant and that any effect of local change in interfacial curvature with distance is negligible. The results from the model are used to extend scaling to include the measured effect of viscosity ratio for linear and radial flow. For the all-faces-open boundary condition, commonly used in core analysis studies, oil recovery vs. imbibition time is estimated by a combination of spherical and radial flow. Consistently close agreement was obtained between experiments and behavior predicted by the model.
Statistical Study of the Crush Resistance Measurement for Ceramic Proppants
Authors: Stephens W. T. , Schubarth S. K. , Rivera D. I. , Snyder E. M. , Herndon D. C.
Published: December 2007

Crush resistance and size distribution are two measurements to select a proppant. While standard sieve analysis provides a good quantitative value for crush resistance, detailed size measurements can provide more understanding of proppant failure and the alteration of size distribution under load. The variance in proppant crush resistance is often larger than the typically reported accuracy of ±0.1%. In many cases, specimen handling and material retention upon sieves makes a real contribution towards measurement error.

This paper documents the variation in crush resistance measurements for proppants of similar size and size distribution at constant stress. Optical measurement of the size distribution can reveal more information about proppant failure under load. The paper discusses the sensitivity of the measurement with respect to manual versus automatic load application, loading rate, cell size, and specimen mass. The accuracy and precision of the test, along with the minimum sample size, are reported. The relationship between size distribution and crush resistance for different proppant materials is also presented.

The results of this paper address expanding the technical evaluation of proppants using new tools and analysis methods to provide a greater understanding of the crush resistance measurement. Operators will be able to select an appropriate proppant for their application with a practical understanding of measurement variation.
Seismically Based Integrated Reservoir Modelling, Lunskoye Field, Offshore Sakhalin, Russian Federation
Authors: Ross Liz , King Kevin , Bodewitz Gerard , van Hasselt Hajo , Stone Greg , Twigt Wim , Swinkels Wim , James Andrew , Addis Tony , Parsons Chris , Meij Robert , Bell Sarah , Trofimov Alexei , Jackson Patrick , Cholovsky Valery , Lamers Edwin , Crouch Syrie
Published: December 2007

The Lunskoye Field is a centrepiece of the Sakhalin II development, one of Shell's most significant current projects. Demand for LNG in the nearby Asia-Pacific market and availability of a large (18.2 Tcf GIIP) gas resource underpins the investment decision in a challenging offshore environment.

Robust suites of seismically-constrained integrated reservoir models were generated to evaluate short-, medium- and long-term subsurface uncertainties. Previous quantitative reservoir mModelling efforts were hampered by the existence of shallow gas over the crest of the structure, which masked the seismic response in the crestal area of the reservoir. This impacted the evaluation of structure and reservoir properties from seismic. To address this, a new 3D-survey was acquired in 2003, in an east-west direction, to undershoot the shallow gas deposits. The Pre-Stack Time Migration and Pre-Stack Depth Migration seismic results show the reservoir image is greatly improved, and there is improved confidence in the seismic signal that allows it to be used for the definition of rock property distribution.

In parallel to the seismic interpretation, a detailed evaluation of velocities, core, and well-log information was undertaken to provide input into an in-house probabilistic model-based seismic inversion (1). This fundamental work was used to: construct an integrated and fully consistent structural and stratigraphic hierarchical framework, in the lateral and vertical domain;update the view of the depositional setting, taking into account variations in provenance and relative sea-level;define the petrophysical parameters for the rock property model, which underpins the inversion.

The results of the model-based inversion formed the basis of the detailed static models and analysis of key subsurface uncertainties. Results of the improved property models were upscaled and fed into the well inflow models and dynamic models to improve productivity estimates, long-term reservoir performance prediction and to support development planning and reservoir management.

This paper summarises all of the refinements undertaken as part of the new model building, including the improvement in the seismic data, the insight into the stratigraphic changes, the hierarchical framework, the rock property model, the probabilistic inversion, the well inflow modelling, and the dynamic simulation.