bluuebunny/crossref_metadata_2025 huggingface dataset:
Chemical and Thermal Effects on Wellbore Stability of Shale Formations
Authors: Yu M. , Chen G. , Chenevert M. E. , Sharma M. M.
Published: December 2007

A new three-dimensional wellbore stability model is presented that takes into account thermal stresses and the flux of both water and solutes from drilling fluids (muds) into and out of shale formations. Mechanical stresses around a wellbore placed at any arbitrary orientation in a 3-dimensional stress field are coupled with changes in temperature and pore pressure due to water and solute fluxes. The radial and azimuthal variation in the stress distribution and the "failure index" are computed to check for wellbore failure. This model accounts for the hindered diffusion of solutes as well as the osmotically driven flow of water into the shale. The model for the first time allows a user to study the role of solute properties on wellbore stability.

Results from the model show that a maxima or minima in pore pressure can be obtained within a shale. This leads to wellbore failure not always at the wellbore wall as is most commonly assumed but to failure at some distance inside the shale. Since the fluxes of water and solute, and temperature, are time dependent, a clearly time dependent wellbore failure is observed. The time to wellbore failure is shown to be related to the rate of solute and water invasion. Comparisons with experiments conducted with a variety of solutes on different shales show excellent agreement with model results.

It is shown in this study that the solutes present in the mud play an important role in determining not only the water activity but also in controlling the alteration of pore pressures in shales. To account for this phenomenon a model is presented to compute the flux of both water and solutes into or out of shales. The relative magnitudes of these fluxes control the changes in pore pressure in the shale when it is exposed to the mud. The effect of the molecular size of the solute, the permeability of the shale and its membrane efficiency are some of the key parameters that are shown to determine the magnitude of the osmotic contribution to pore pressure. A range of behavior is observed if the solute is changed while the water activity is maintained constant. This clearly indicates the importance of the solute flux in controlling the pore pressure in shales.

Critical mud weights are obtained by inspecting the stability of the wellbore wall and the entire near wellbore region. Pore pressures at different time and position are investigated and presented to explain the model results. It is shown in this study that the critical mud weights are strongly time dependent. The effects of permeability, membrane efficiency of shale, solute diffusion coefficient, mud activity and temperature changes are presented in this work. The collapse and fracture effects of cooling and heating the formations are also presented.

A powerful tool has been developed which can be used to perform thorough investigations of the wellbore stability problem. A user-friendly interface has been developed to ease usage.
Underbalanced and Low-head Drilling Operations: Real Time Interpretation of Measured Data and Operational Support
Authors: Lorentzen Rolf J. , Fjelde Kjell Kåre , Frøyen Jonny , Lage Antonio C. V. M. , Nævdal Geir , Vefring Erlend H.
Published: December 2007

The accurate prediction of the downhole pressures and the returning flow rates in low-head drilling (LHD) and underbalanced drilling operations (UBD) is a major concern in the oil industry. The present work shows an original formulation of a dynamic two-phase flow model based on the classic drift-flux set of conservation equations. However, differently from the traditional approach, the closure of the system is obtained by using measured data acquired during the execution of the operation. The innovative concept consists of utilizing mechanistic models that are dependent on unknown parameters. These parameters and the model state are calculated and updated on a regular basis to minimize the differences between model predictions and measured data.

The potential of this new approach is discussed by presenting some transient examples of application. The current study represents a continuation of previous work on real time data interpretation1, and a step in the development of a methodology for the introduction of learning while drilling process in the hydraulic design and follow-up of LHD and UBD operations.
Generalized Hydraulic Calculation Method Using Rational Polynomial Model
Authors: Pilehvari Ali , Serth Robert , Lagad Vishal
Published: December 2007

Abstract: Current methods of hydraulic calculations for non-Newtonian fluids encountered in the oil fields necessitate, as a first step, determination of an appropriate fluid model, e.g., Bingham plastic or yield power law. The calculated parameters of the chosen fluid model are then plugged into the corresponding set of hydraulic formulas.

In this study, a generalized hydraulic calculation technique has been developed and programmed that requires as input only the raw rheological data for the fluid and the values of the relevant hydraulic parameters. It is not necessary to incorporate in the program the many empirical models currently used to represent non-Newtonian fluid behavior and the associated logic to determine which model is appropriate for a given set of rheological data. The new hydraulic calculation technique is based on two important developments.

First, a new and powerful rheological model, called Rational Polynomial (RP), has been developed. Using a variety of data from the literature, it is shown that the rational polynomial model is capable of accurately representing the rheogram of virtually any time-independent fluid.

Second, a generalized hydraulic calculation procedure has been developed which is applicable to any time-independent non-Newtonian fluid. The Rabinowitsch-Mooney1 equation is integrated numerically utilizing the rational polynomial correlation. For laminar flow, this integration directly provides the solution for flow rate versus pressure drop. The integration also provides the parameters needed in the calculation of turbulent flow utilizing the generalized power law procedure developed by Metzner and Reed2.

The predictions of the developed method have been compared with several sets of experimental hydraulic data from different sources, gathered from large-scale flow loops.

The tested cases include laminar and turbulent flow of various drilling fluids in both pipe and annular geometry. The predictions of the rational polynomial and the generalized hydraulic calculation method are shown to be quite accurate and superior to those obtained by the currently available standard techniques.
New Testing Protocols and Regulatory Guidelines to Promote Further Development of Synthetic-Based Fluid Technology
Authors: Friedheim James E. , Candler John E. , Rabke Stephen P.
Published: December 2007

Since the introduction of synthetic-based mud (SBM) technology in the Gulf of Mexico, stakeholders have worked toward realization of the pollution-prevention aspects of SBM technology without losing the benefits of enhanced drilling performance. In addressing the issues of SBM in the Coastal Effluent Limitation Guidelines, the U.S. Environmental Protection Agency (EPA) recognized the pollution-prevention potential for SBM technology, but also determined that the exiting test protocols needed to be improved to measure environmental performance. In response to the Coastal Effluent Limitation Guidelines, industry work groups, including EPA scientists and engineers, took on the specific tasks of identifying and modifying test protocols that would allow continued positive development of SBM technology. The resulting test protocols for biodegradation, toxicity and analytical chemistry as described in the Effluent Limitation Guidelines for SBM technology will form the structure for usage of existing non-aqueous fluids and development of new fluids and fluid blends.

This paper details the process of protocol and regulatory development, which is a success story applicable to other regulatory arenas and other issues in the U.S. The resulting regulatory framework and technology will lead to U.S. offshore operations becoming the hot bed of pollution prevention in the global offshore drilling community. The authors will show how continued use of SBM technology in the Gulf of Mexico will allow successful development of deepwater petroleum resources in an environmentally responsible manner.
Laser Drilling: Determination of Energy Required to Remove Rock
Authors: Gahan B. C. , Parker Richard A. , Batarseh Samih , Figueroa Humberto , Reed Claude B. , Xu Zhiyue
Published: December 2007

Samples of sandstone, limestone, and shale were prepared for laser beam interaction with a 1.6 kW pulsed Nd:YAG laser beam to determine how the beam's size, power, repetition rate, pulse width, exposure time and energy can affect the amount of energy transferred to the rock for the purposes of spallation, melting and vaporization. The purpose of the laser rock interaction experiment was to determine the threshold parameters required to remove a maximum rock volume from the samples while minimizing energy input.

Absorption of radiant energy from the laser beam gives rise to the thermal energy transfer required for the destruction and removal of the rock matrix. Results from the tests indicate that each rock type has a set of optimal laser parameters to minimize specific energy values as observed in a set of linear track and spot tests.

In addition, it was observed that the rates of heat diffusion in rocks are easily and quickly overrun by absorbed energy transfer rates from the laser beam to the rock. As absorbed energy outpaces heat diffusion by the rock matrix, local temperatures rise to the minerals’ melting points and quickly increase SE values. The lowest specific energy values are obtained in the spalling zone just prior to the onset of melting.
Three-And Four-Phase Flow Compositional Simulations of CO2/NGL EOR
Authors: Guler Baris , Wang Peng , Delshad Mojdeh , Pope Gary A. , Sepehrnoori Kamy
Published: December 2007

CO2 mixed with NGL is being evaluated as a method to enhance viscous oil recovery from Schrader Bluff and other oil reservoirs at Milne Point, Alaska. The sequestration of CO2 is a secondary objective of these proposed projects. Mixtures of CO2 and NGL with the crude oil show a large three-phase liquid-liquid-gas region, so three and four-phase flow may occur in the reservoir when water is alternated with the miscible injectant. A compositional EOS simulator has been used to simulate the oil recovery for both three-phase and four-phase flow cases. The objective was to understand how important it is to simulate four-phase flow rather than use a three-phase flow approximation. Two methods were used to model three and four-phase relative permeabilities from two-phase relative permeabilities as well as to evaluate the sensitivity of the results to the relative permeability parameters. A two-dimensional vertical cross-section of the reservoir was modeled with a stochastic permeability field to approximate heterogeneities. These simulations clearly show that under these conditions, four-phase flow is significant. Four-phase flow occurs over a significant part of the reservoir and affects both the sweep efficiency and the injection and production rates when the wells are pressure constrained and the production pressure corresponds to the three-phase region of the phase diagram. The results are also very sensitive to the relative permeability parameters regardless of which relative permeability model is assumed. The project life is particularly sensitive to the relative permeability and is longer for four-phase flow than predicted by a three-phase flow approximation because the relative permeability of each phase is lower when four phases are modeled.
Evaluation of Cyclic Steam Operations at Cymric 1Y Diatomite
Authors: Ambastha A. K , Kumar M. , Skow L. A. , Evola G. M.
Published: December 2007

Cymric 1Y is a heavy oil diatomite reservoir in California, U.S.A. with an estimated original oil-in-place (OOIP) of 425 MMSTB. Diatomite reservoirs have low permeability (average of 5 md or less) and high porosity (50-60%).

The primary objective of this study was to investigate future development options using a consistent Base case for the cyclic operation in the 1Y pilot area. Field data from the in-fill pilot area, with a well spacing of 5/8-acre, and a fine-grid simulation of a four-well segment was used in this study.

Results show that fine grids (of the order of one ft), perpendicular to the steam-induced fracture orientation, are necessary to properly capture the effects of sharp temperature and saturation gradients in the primary fluid flow direction. Initial saturation, reservoir matrix permeability, fracture halflength, capillary pressure, and flowing bottom-hole pressure were identified as key parameters at Cymric 1Y.

Results also show that the cyclic steam development at 5/8-acre may result in 22% recovery. Infilling to 5/16-acre spacing could increase the recovery to 34% OOIP. Success of steam drive at Cymric 1Y would require that fractures remain open at both injectors and producers. A successful steam drive could further boost the ultimate recovery.
Novel Push-Pull Displacement Method to Determine Relative Permeability Hysteresis in Heavy Oil Reservoirs
Authors: Okazawa Tadahiro , Serres Anita J. , Rancier Douglas G. , Corry Kathleen E.
Published: December 2007

For heavy oil reservoirs it has been a very difficult task to determine relative permeability curves using reservoir fluids. In the steady-state method, saturation is quite insensitive to variation of fractional flow of phases due to the severe mobility contrast between the injected phase and the displaced phase. The Displacement method works fine for the imbibition process where high-mobility water displaces low-mobility heavy oil; however, it does not work for the drainage process where the displacement is almost piston-like, hence the information on fractional flow obtained is limited to a very narrow high oil saturation range and is not useful.

The new method consists of two test stages. First, to determine the imbibition relative permeability using the displacement method. Second, to undertake a push-pull displacement test to determine the drainage relative permeability. The first portion of the push-pull test is a repetition of the imbibition test to the point of breakthrough. Having known the imbibition relative permeability, one can determine the saturation profile in the sample core at the end of the imbibition process. At the expected breakthrough point, the flow is reversed by oil injection from the original producing end of the core. The well-distributed saturation profile at the start of the drainage process provides information on the fractional flow in a wide range of saturation. History of production of water and oil from the original injection end and pressure drop across the core determines the drainage relative permeability.

The method was applied to preserved cores from the Clear Water formation of the Cold Lake oil-sand reservoir as well as to silica-sand packs. The tests were performed using cleaned Cold-Lake bitumen and simulated formation brine at a temperature range from 100 C to 180 C which represent stages in the cyclic steam stimulation process in Cold Lake. The test results exhibited little evidence of relative permeability hysteresis.
Design of Tubing Collar Inserts for Producing Gas Wells Below Their Critical Velocity
Authors: Putra Satya A. , Christiansen Richard L.
Published: December 2007

Liquid production can be a serious problem in gas wells if there is inadequate energy to lift the liquid from the well bore. The liquid accumulation problem in gas wells is known as liquid load up, causing a well to die early. And it is commonly start when gas wells produce below the Turner critical velocity. This paper presents research on a new technology for liquid lifting in gas wells, so that it can produce below the critical velocity.

The liquid lifting technology that was developed is a lifting device, called inserts, that are placed in the production string of a gas well. The study for liquid lifting with inserts was done in an experimental flow loop. Various aspects of insert design were studied, such as insert opening, insert spacing, effect of liquid and gas flow rates, and performance of different types of inserts. Experimental studies in the flow loop show that inserts are able to enhance liquid lifting with two mechanisms: lifting by droplet transport, and lifting by inhibition of downward liquid fluctuation.

From the experiments on the flow loop and case studies with the gas well model with inserts, which include the mechanistic churn flow model, criteria for application of inserts in gas wells were proposed: the flow pattern should be in churn flow, the gas superficial velocity should be below the critical velocity of Turner et al., and there should be no excessive pressure drop caused by flow through inserts.
Estimating Multiphase Flow Properties Using Pressure and Flowline Water-Cut Data from Dual Packer Formation Tester Interval Tests and Openhole Array Resistivity Measurements
Authors: Zeybek M. , Ramakrishnan T. S. , Al-Otaibi S. S. , Salamy S. P. , Kuchuk F. J.
Published: December 2007

Multiphase flow and production cuts are affected significantly by relative permeabilities under reservoir conditions. Yet their in-situ determination is practiced only in isolated cases, and these have used array resistivity logging. Although wireline dual-packer formation-testers provide direct flow tests, analysis thus far has been confined to the determination of single-phase permeability and anisotropy. In this paper, we present a methodology to integrate the formation tester pressure and water-cut measurements with openhole array resistivity measurements to obtain relative permeabilities of oil and water.

It has been demonstrated previously that the filtrate invasion process, although uncontrolled, contains quantitative information of the fractional flow curve. The sampling process is similar; it is described by the multiphase/multi-component flow equations for which the initial condition is set by the invasion process. Geometrically, while the invasion process is largely cylindrical, the sampling process is not. To combine the two, we parameterize the invasion problem in terms of multiphase flow properties and drilling conditions, and carry out a simulation exercise, including generation of resistivity logs. The fractional flow parameters obtained, by matching the observed resistivity logs are then used for modeling fluid sampling with a formation tester. Comparison of the simulation results with the observed water-cut and pressure data allowed for further refinement of the relative permeability curves. A field example of the application of the above methodology will be discussed.
A Variable Block Size Model for the Characterization of Naturally Fractured Reservoirs
Authors: Rodríguez-N. Rafael , Cinco-L. Héber , Samaniego-V. Fernando
Published: December 2007

A variable block size model is presented to study naturally fractured reservoirs, taking into account continuous uniform, exponential and normal distributions of matrix block sizes. The work is based on the transient matrix flow and is an extension of the analytical model formulated by Cinco, Samaniego and Kuchuk for a finite number of block sizes. Several new groups of the pressure derivative function were developed to study the features of their graphical representation in log-log scales, to determine the matrix block size distribution corresponding to a certain shape of the curves. These groups are a better diagnostic tool than the conventional pressure derivative function, specially for pressure data on the transition period between the fracture storage dominated flow and the matrix pseudosteady-state flow. The solutions are obtained in the Laplace space, involving an integral which is numerically solved.
Nonlinear Regression: The Information Content of Pressure and Pressure-Derivative Data
Authors: Onur M. , Reynolds A. C.
Published: December 2007

It is shown that commonly used procedures for estimating parameters by regressing on pressure derivative data are based on incorrect covariance matrices and thus violate the underlying statistical basis for nonlinear least squares parameter estimation. Although the resulting estimates of model parameters may be reasonable, calculated confidence intervals are meaningless. Here, we show how to compute the correct derivative data covariance matrix that should be used for estimating parameters by nonlinear least squares. It is also shown that the information content of derivative data cannot be greater than the information content of pressure data in the sense that regression on derivative data with the proper covariance matrix will not yield smaller confidence intervals than those obtained by regressing on pressure data only. In fact, we prove that matching a data set including all interior derivative data plus two appropriate pressure points will yield exactly the same estimates and confidence intervals that would be obtained by regressing on pressure data only.
Theory and Analysis of Injectivity Tests on Horizontal Wells
Authors: Peres Alvaro M. M. , Reynolds Albert C.
Published: December 2007

This work addresses the behavior and analysis procedures for injectivity tests on horizontal wells completed in an oil-bearing reservoir. In general, pressure and pressure derivative behave quite similar to the single-phase solution calculated with oil properties, thus flow regimes can be identified by log-log plots. However, skin factor and effective well length estimates are severely affected if one neglects the effect caused by the contrast in fluid mobility. A simple approximate analytical solution for the wellbore pressure is derived in this work. The accuracy of this solution is verified by comparison of results obtained from a reservoir simulator using hybrid grids and local grid refinement. The analytical solution, supported by simulator results, indicates that the injected water going through a damaged zone has a strong and distinctive effect on both pressure and pressure derivative behavior at early times. It is also shown that, if relative permeability data are available, an equivalent single-phase data can be constructed from the measured wellbore pressures. These equivalent single-phase data can be analyzed by standard single-phase flow techniques for horizontal wells, providing reliable estimates for effective permeability, skin factor and effective wellbore length.
Trends in Reservoir Simulation: Big Models, Scalable Models? Will you Please Make up Your Mind?
Authors: Gorell Sheldon , Bassett Robert
Published: December 2007

Over the past 20–30 years, reservoir simulation technology has gone through various stages of acceptance and utilization. This paper will discuss the most common workflows as well as several of the emerging trends in reservoir simulation technology, particularly: 1) building ever larger increasingly complex simulation models, 2) building smaller models, which can be evaluated quickly, and 3) building scalable or "fit for purpose" models. This paper will discuss these trends in more detail, reconcile these approaches and discuss the appropriateness of each method. Potential conflicts with respect to the user profile and the differing demands imposed on development and usage of a reservoir simulation system will also be discussed relative to each of these workflows.
Technique to Integrate Production and Static Data in a Self-Consistent Way
Authors: Landa Jorge L.
Published: December 2007

This work presents a technique to integrate production data into the reservoir characterization workflow.

The application of the technique ensures that the construction of earth models for reservoir simulation will be geologically sound and consistent not only with all the observed static and production data, but also with the earth modeling workflow philosophy, regardless of its complexity.

The technique can be considered as an advanced reservoir simulation history matching process with a complex level of parameterization. The observed production data is applied to adjust the key parameters in the workflow used to construct the static model. The magnitude of the parameter adjustments is dependent on the uncertainty associated with the parameters.

The problem is posed as an inverse problem and it requires the computation of the sensitivity coefficients of the field responses (production data) with respect to the parameters for inversion.

This paper also introduces the concept of "static" sensitivity coefficients and explores their usefulness.

An example is presented where the parameters for inversion included variogram parameters along with the mean and variance of a reference porosity histogram. The inversion was performed by adjusting parameters in the fine scale model while the production data was computed in an upscaled model.
Application of New Viscoelastic Fluid Technology Results in Enhanced Fracture Productivity
Authors: Weaver J. , Parker M. , Slabaugh B. , Walters H. , Haley W. , Bone G. , Hensley J. , Vashler J.
Published: December 2007

Water-based polymers, guar, and derivatized guar have been the mainstay of fracturing fluids for many years because of their low cost and highly controllable fluid rheology. However, these materials can cause significant fracture conductivity impairment leading to poorer than expected well productivity after fracture stimulation. Considerable effort has been applied to reduce the damage caused by these fluids, including: (1) applying special purification chemical processes, (2) improving polymer breakers, (3) formulating fluids with less polymer, and (4) improving fluid recovery during well flowback after treatment. Each of these processes has incrementally improved conductivity; however, one-half or more of the native conductivity is lost to frac fluid damage derived from the use of guar-based polymers.

Recent application of no polymer, surfactant-based viscoelastic frac fluid technology has demonstrated the value of non conductivity damaging fluids by generating high well productivity with small fracture stimulation treatments. While these fluids are generally nondamaging, they are limited in applicability because of high fluid loss and their inability to generate extended fractures at a reasonable cost.

This paper presents the laboratory development and initial field testing of a new, viscoelastic fluid technology that produces highly productive fractures with low conductivity damage while providing excellent fluid-loss control and high proppant-transport properties to generate design fracture geometry. This fluid has little sensitivity to temperature and salinity, and rheology is easily controlled. The fluid system combines the best properties of polymer-based fluid technology with those of surfactant-based technology.
Multilateral Junction Connectivity Discussion and Analysis
Authors: Ohmer Herve , Brockman Mark , Gotlib Mikhail , Varatharajan Prana
Published: December 2007

Multilateral junction connectivity failures have been identified as a recurring risk when deploying junctions featuring casing windows in unstable formations. Connectivity has previously been described as a property defining general mechanical attributes such as resistance to formation loads of the constructed junction. When a junction experiences a connectivity problem, usually because unstable formations induce mechanical loads, solids can intrude and expected junction geometry can deteriorate.

This paper explores the main connectivity issues and redefines the functional and technical requirements. An analysis of potential solutions illustrates that casing is not a suitable structural component when a full-size window is created. Our design introduces a structural layer internal to the parent casing, composed of two main prefabricated parts that create a lateral junction. A template braces the parent bore adjacent to the window, and a lateral connector interlocks with the template in such a way that it effectively supports axial and radial mechanical loads while creating a barrier against migration of formation solids. Case histories and laboratory testing confirm the structural integrity of our simple, two-trip junction construction method.
Aconcagua, Camden Hills, and King's Peak Fields, Gulf of Mexico Employ Intelligent Completion Technology in Unique Field Development Scenario
Authors: Jackson Nielsen Victoria B. , Piedras Jose , Stimatz Gregory P. , Webb Tamara R.
Published: December 2007

Economic success of deepwater and ultra-deepwater developments often depends on the use of innovative technologies that can increase production and minimize workover needs to achieve the sought-after field efficiency during the productive life of the field. Intelligent completion technology, a new concept for the oilfield, is one of the technologies that can support these needs. This well completion concept allows the operator to obtain real-time or near-real-time reservoir data, and then, to reconfigure the wellbore production/injection architecture to adapt to the information obtained.

Along with pipeline, platform, and subsea system synergies, three fields in the Gulf of Mexico — Aconcagua, Camden Hills, and King's Peak — are using intelligent completion technology to optimize a marginal reserve base. Located in Mississippi Canyon Blocks 173, 217, 305, 348 and Desoto Canyon Blocks 133 and 177 in 6200- to 7200-ft of water, the production from the three fields will be tied to the Canyon Station host platform, 55 miles from the most distant well location.

Though slight variations exist between the intelligent completion systems being installed in the three fields, the basic design in each consists of:

A production packer with a hydraulic and electric bypass A gauge package for measuring shut-in and flowing pressure from two sand-controlled zones 2 control valves with metal-to-metal seals to control flow from both production intervals A shroud to isolate flow between upper and lower production intervals.

The piston-actuated control valves will be functioned through a direct hydraulic link from the subsea control module. Pressure applied at the subsea control module will allow hydraulic fluid to be directed to the open side of one piston, the open side of the other piston, or the close line, which is common to both valves.
Measuring Formation Anisotropy Using Multifrequency Processing of Transverse Induction Measurements
Authors: Tabarovsky L. A. , Epov M. I. , Rabinovich M. B.
Published: December 2007

Multi-frequency processing of transverse induction measurements (3D Explorer - 3DEX™) allows us to reduce the distortion of interpretation by near-borehole effects. Recently, we have developed a multi-frequency processing technique for determining formation anisotropy in vertical and deviated wells. The method, based on a separation of induction and galvanic modes, provides a fast and stable indicator of anisotropy in real time.

We consider a borehole oriented along the Z-axis. Axes X and Y are positioned in a perpendicular plane. The set of measurements under consideration includes XX, YY, and ZZ data. The magnetic field XX is excited by an X-oriented transmitter and measured by an X-oriented receiver. Similar definitions are true for YY and ZZ components.

We start processing by performing a multi-frequency skin-effect correction on the measured XX, YY, and ZZ data. Correction pre-conditions the data for rotation from the tool coordinate system to the formation coordinate system. As a result of the rotation, we calculate responses XX', YY', and ZZ' where axis Z' is orthogonal to the formation boundaries. Axes X' and Y' belong to the boundary planes. The rotation of multi-frequency processed data does not require knowledge of the full tensor of electromagnetic measurements: the rotation can be done only with the principle components XX, YY, and ZZ.

Rotation isolates the induction mode in the ZZ component and removes the dependence on the vertical conductivity. This allows for applying a very fast processing technique to calculate horizontal resistivity of the formation, Rh. The technique utilizes a modified geometric factor with the transmitter and receiver shifted horizontally with respect to each other.

Next, we produce a synthetic response for XX' and YY' components in an isotropic model with formation resistivity, Rh. The calculated synthetic response is used to correct the field data for the horizontal conductivity. If the formation is isotropic, the corrected signal will be equal to zero. A nonzero residual signal indicates the presence of anisotropy.

The methodology is illustrated with several examples.
Utility and Reliability of Cemented Resistivity Arrays in Monitoring Waterflood of the Mansfield Sandstone, Indiana, USA
Authors: Bryant I. D. , Chen M. -Y. , Raghuraman B. , Raw I. , Delhomme J. -P. , Chouzenoux C. , Pohl D. , Manin Y. , Rioufol E. , Oddie G. , Swager D. , Smith J.
Published: December 2007

In 1999 an oilfield experiment was initiated to test the application of electrical measurement technologies to permanent reservoir monitoring. The principal objective of the experiment was to demonstrate the feasibility of monitoring water movement between an injection and observation well. This paper describes the utility of the data provided by the resistivity arrays and discusses data quality and reliability of the measurements.

Two wells were drilled into the Mansfield sandstone reservoir in Indiana. The D-8 injector well was located in the center of four development wells. The OB-1 monitoring well was offset 233 ft to the southwest in a location midway between the D-8 injector and the No. 3 production well. The injector was instrumented with a 16-electrode resistivity array that was run on the outside of insulated casing and cemented into the annulus of the well. A similar array was cemented into the annulus of the monitoring well.

In March, the D-8 well was perforated and acidized. A surface gauge was used to monitor injection rates and pressures. Initially, injection proceeded at a rate of about 20 B/D, increasing to 100 B/D after fracture stimulation. The D-8 array records responses to perforation, acidization, swabbing, fracturing, and injection. It clearly distinguishes the movement of the waterfront in different zones. The data show good signal-to-noise ratio and high reciprocity. The OB-1 electrical array clearly indicates early water breakthrough via an induced fracture. The arrays show no degradation of signal over the 17-month duration of the experiment.

The experiment has demonstrated the viability of using permanently installed resistivity arrays to monitor movement of oil-water contacts that are some tens of feet away from the wellbore. Results demonstrate the feasibility of using such arrays to monitor oil-water contact movements remote from injection, monitoring, and production wells.
Optimization of Wireline Sample Quality by Real-Time Analysis of Oil-Based Mud Contamination - Examples from North Sea Operations
Authors: Fadnes Finn Hallstein , Irvine-Fortescue Jamie , Williams Stephen , Mullins Oliver C. , Van Dusen Alexandra
Published: December 2007

Oil Based Mud (OBM) systems are often required to be able to drill a well successfully. Their use generally results in a better quality well-bore and reduced drilling time. Unfortunately, this can also result in increased environmental issues as well as difficulties in accurate formation evaluation. One area of formation evaluation that can suffer greatly when OBM is used is wireline fluid sampling. High levels of the miscible OBM filtrate in the final sample render fluid characterisation results questionable and often useless. To obtain high quality oil samples the sampling method and mud system need to be optimized in order to minimize the contamination level.

When an accurate measurement of the level of contamination cannot be made and therefore the amount of miscible filtrate cannot be corrected for, the resulting fluid characterization cannot be trusted. Discrepancies in the current methods of measuring contamination have left many unanswered questions. Furthermore, the resulting reservoir parameters are questionable and must often be discarded.

The ability to measure contamination in real-time while sampling offers an opportunity to revolutionize the sampling method, optimize sample quality, and improve the final results. In addition, this offers the possibility for significant savings in operational time. Analyses of oil samples taken in OBM in the North Sea have shown that it is possible to estimate contamination while sampling using the optical properties of the OBM filtrate and the crude oil. Although these estimates may differ from those obtained through contamination measurements at surface, in several case studies addressed in this paper the downhole contamination estimation proved to be more accurate for a given sample than the corresponding contamination measured at surface. This paper examines oil samples from wells drilled with OBM and discusses the ability to predict downhole contamination from their case histories. The research shows that real-time contamination measurements will lead to improved fluid characterization and consequently improved reservoir engineering.
Decommissioning Offshore Oil and Gas Fields
Authors: Ruivo Fábio M. , Morooka Celso K.
Published: December 2007

Decommissioning offshore oil and gas production systems have been progressively increasing the concern of the industry, government and interest groups through the last years. There are at least two reasons for this sudden regard. First, it is the maturing of several oil and gas fields around the world in recent years. Second, it is the growing impact of environmental concerns in international affairs.

Despite several works published address to some techniques and to potential problems and risks related to decommissioning offshore oil and gas production installations, its procedures are in some extent an innovative issue, especially in the case of deep-water fields such as the Brazilian ones.

Therefore, the motivation of this paper is the novelty of the subject in Brazil, since the national industry is just beginning to deal with the end-of-leasing obligations, which involve decommissioning operations, and the governmental regulatory agency is filling the current gaps in the official guidelines. The main ambition is to stimulate debate about pertinent issues.
A New Generation Multilateral System for the Troll Olje Field - Development and Case History
Authors: Berge Frode , Hepburn Neil , Bowling John , Gronas Tore
Published: December 2007

Norsk Hydro’s Troll Olje field will require about 25 multilateral wells in order to drain the field using the existing sub-sea template structure.

Prior to the development of the Isolated Tie-Back System (ITBS™) described in this paper, three multilateral wells had been installed on the Troll Olje field using System 4503. On these TAML Level 4 wells, junction isolation was achieved with special cement and a resin squeeze. Junction related production problems were experienced on two of the wells with lumps of resin flowing back and plugging surface equipment. One well cleaned up rapidly, whereas the other is currently shut down. The MLT operations on these wells had been completed in 22 days, 17.9 days and 14.6 days, respectively. Although all wells were technically successful and the trend was good there would be a lower limit around 12 days due to all the milling operations required establishing the initial exit and the re-entry to the main bore. In order to further improve the reliability of the junction and the installation time, a new system would be required.

After an evaluation period, the operator (Norsk Hydro) accepted a proposal from Sperry-Sun/ Halliburton to further develop their existing prototype Isolated Tie-Back System for use on Troll Olje. ITBS™ will provide both hydraulic and mechanical isolation, a combined flow area that is larger than that of the tubing above, and an acceptable solution for access to main bore and lateral. The long term objective was to install this TAML Level 5 system in less than six days.

ITBS™ is a multilateral system based on a pre-milled window and on a latch coupling placed in the 9-5/8-in. liner section. After installation of screens in the main bore reservoir section, a whipstock is installed in the latch coupling and the window opened up to drill the lateral. To complete the well, the whipstock is retrieved and replaced by a deflector; and a multilateral junction system is then installed as an integral part of the lateral bore completion. The main component is a flexible hanger with D-shaped legs. This component is attached to the lateral liner on one leg and has a stinger on the other leg. The stinger is oriented and lands in a seal stack in the main bore deflector. On Troll Olje, screens are installed in both the main and lateral bore and the lateral liner is not cemented across the junction. An early prototype of the system was developed in 1998/99. The system was then further developed during 2000 and the first installation conducted for Norsk Hydro in the Troll Olje field in Norway. This paper will discuss the development of the ITBS™ system and also the first installation from a floating rig in the Troll Olje field.
Microbial Enhanced Oil Recovery (MEOR) Technology in Bokor Field, Sarawak
Authors: Ghazali Abd. Karim M. , Hj Salim Mat Ali , Md. Zain Zahidah , Talib Noor Nazri
Published: December 2007

Bokor field was selected as the first field in Malaysia for Microbial Enhanced Oil Recovery (MEOR) technology application which utilizes micro-organisms to facilitate, increase or extend oil production from reservoir through the production of biochemical such as biosurfactant, solvents, gases and weak acids. The field was selected due to its high viscosity crude (4 to 10 cp) and low oil specific gravity of 20° API which could resulted in low recovery factor in major reservoirs ranges from 19% to 25% of its original oil in place. This technology also seems to be attractive for the field as it was initially thought to be potential for for reducing the viscosity of the oil and thus improve oil recovery. In addition, reservoir properties for major reservoirs in Bokor field conform to the basic screening criteria of the MEOR application.

This paper mainly discusses the results of the pilot project on MEOR technology application in Bokor field1. A feasibility study focusing on candidate selection and comprehensive laboratory analysis was conducted to investigate the feasibility of this technology for improving oil production/recovery. Generally, the feasibility study had indicated that there is a potential oil production improvement with no near wellbore impairment. Biodegradation study on the crude sample indicates complete removal of normal/branched alkanes and partial removal of aromatics due to in-reservoir alteration. Laboratory inoculation on the wellhead crude sample indicated that the microbes were able to slightly reduce the viscosity, break the emulsion and increase the solubility of high molecular weight component without damaging the reservoir. In order to prove the laboratory results and further assess the impact to oil production, a pilot test on three (3) selected wells were carried out. A comprehensive monitoring strategy was developed and the performances were monitored for 5 - 6 months.

Over 5 months period, results from the pilot were found to be encouraging. Significant increase in oil production rate and reduction of water cut were observed demonstrating the effectiveness of MEOR application. The average oil production rate for the period increases by 270 b/d which is equivalent to 47% oil incremental.
Microbial EOR Laboratory Studies on the Microorganisms Using Petroleum Hydrocarbon as a Sole Carbon Source
Authors: Han Peihui , Sun Fengrong , Shi Mei
Published: December 2007

Eight kinds of facultative anaerobes using petroleum hydroc-arbon as sole carbon source are screened out from hundreds of oil-bearing waste water samples based on physical and ch-emical condition of Daqing oil field. Systematic biochemical property evaluation and core-flooding experiment show that the eight kinds of facultative anaerobes can grow and repro-duce on crude oil under anerobic condition. They also can de-grade crude oil and decrease its viscosity, produce active substance and reduce the interfacial tension (IFT) between fermented solution and crude oil. Chromatographical analysis shows that the light component of oil which has treated with bacteria increases by 30%, ΣC21-/ΣC22+ increases by 54%.The oil movability got better. Pr /nC17 and Ph/nC18 increases by 55% and 57% respectively. The PH value of the fermented solution reduces from 7 to 5. The acid content in the fermented solution increases from 17.57mg/L to 948.83mg/L. The IFT between fermented solution and crude oil reduces form 35.67mN/m to 8.10mN/m. The viscosity of crude oil decreases from 28.1mPa·s to 18.06mPa·s. The oil recovery by the microbial flooding is about 10%OOIP over that of the water flooding. How the microbes displace the residual oil was directly observed by an electronic microscope during a microscopic core flooding experiment.
Sensitivity Study On Geomechanical Properties To Determine Their Impact On Fracture Dimensions And Gas Production In The Khuff And Pre-Khuff Formations Using A Layered Reservoir System Approach, Ghawar Reservoir, Saudi Arabia
Authors: Zillur Rahim , Al-Qahtani Mohammed Y.
Published: December 2007

A finite-difference hydraulic fracturing simulator has been used to determine fracture growth and geometry in the Khuff and Pre-Khuff formations of the Ghawar gas reservoir. A layered reservoir system approach has been used where each reservoir is divided into several layers based on the geomechanical and flow properties and reservoir lithology. Single and multiple perforated interval scenarios have been studied to compute fracture growth and proppant transport. The effects of geomechanical properties such as in-situ stress, Young's modulus, closure pressure, and rock embedment strength on fracture dimensions have been investigated. Effects of fluid properties such as, injected volume, percentage of pad fluid, leakoff coefficient, etc. have also been investigated.

Several examples with actual field data have been presented in the paper for reservoirs with multiple producing zones in which fracture is initiated in one or many intervals simultaneously so that the impact of perforations, mechanical properties, and flow characteristics could be identified and calculated. These examples illustrate the importance of knowing the formation properties correctly and choosing the most appropriate treatment size and perforation strategy to effectively fracture a reservoir.

A sensitivity study on incremental gas production is also presented in the paper. This study illustrates production increase as functions of reservoir and fracture properties and provides a guideline to optimally choose fracture length and conductivity for an economic and efficient fracture treatment.