bluuebunny/crossref_metadata_2025 huggingface dataset:
Laminated Sand-Shale Formation Evaluation Using Azimuthal LWD Resistivity
Authors: Bootle Richard , Waugh Matthew , Bittar Michael , Hveding Frode , Hendricks William E. , Pancham Shivanand
Published: October 2009

Intervals of thinly bedded hydrocarbon-bearing sands and laminar clay cannot be fully evaluated with conventional log measurements and interpretation techniques. This is because the laminar nature of the clay component suppresses the logged deep resistivity measurements and results in calculated values of water saturation that are artificially high. This formation evaluation challenge is already widely recognized by the industry and addressed by an interpretation solution that uses simultaneous measurements of horizontal and vertical resistivity, available from the new generation of wireline induction-resistivity tools.

A newly deployed logging-while-drilling (LWD) sensor now provides equivalent measurements of azimuthal resistivity; this technology was deployed for the first time for the formation evaluation of thinly bedded sands in Trinidad's Dolphin Field. This tool provides multiple depths of investigation and 32 azimuthal resistivity measurements. Horizontal and vertical resistivity are extracted from the multi-spacing and multi-frequency azimuthal data using fast and robust inversion algorithms. The results were validated with a back-to-back run with an equivalent wireline service.

An interpretation methodology is presented that sets out the equations used for the mathematical solution of these data. The Thomas-Stieber method is used to partition the calculated clay volume into its laminated, structural, and dispersed components and to calculate the effective and total porosity of the sand fraction of the reservoir. The corresponding true resistivity of the laminated sand fraction is derived from the quadratic solution of horizontal and vertical resistivity and the laminar clay volume. The water saturation of the sand fraction is calculated using the Archie Equation and subsequently volumetrically weighted to provide the total water saturation. The Thomas-Stieber parameters are also used to calculate the formation averages.

The high angle, high step-out wells drilled in this phase of field development have calculated hydrocarbon pore volumes of up to 33% greater than historic, near-vertical wells logged with conventional resistivity tools only. The results of the thin bed interpretation are observed to be sensitive to both borehole deviation and the stratigraphic interval.
Geomechanical Coupled Poromechanics Solutions While Drilling in Naturally Fractured Shale Formations with Field Case Applications
Authors: Nguyen Vinh X. , Abousleiman Younane N. , Hemphill Terry A.
Published: October 2009

Numerous wellbore instability problems have been reported when drilling through chemically active naturally fractured shale. It is usually accepted that wellbore collapses are caused by excessive effective stress concentrations at or near the borehole wall, and excessive mud losses are due to fracturing the rock formation. Since both the pore pressure differential and mud/shale chemical activity modify the effective stresses in the wellbore wall, the cures for such intricate instabilities are therefore in a wellbore solution that accounts for fractures, intact matrix mechanics, and the balance of mud density and salinity. In this work, the effects on collapse and fracture gradient window due to mud chemistry and densities are evaluated through the salinity, membrane efficiency, and the existing natural fracture network. The coupled poromechanics analytical solutions of fracture and matrix dual pressures and stresses predict large variations in the collapse and fracture gradient when compared to wellbore stability in non-fractured shale formations. The physical and mathematical solutions follow the coupled poroelasticity Biot theory through modeling fracture and matrix as dual-porosity and dual-permeability porous media. The solution is helpful in the prediction and visualization of time-dependent alteration of near-wellbore effective stress concentration and the effects on the mud-weight window when compared to non-fractured shale. Specifically, the solution is applied to assess wellbore stability for a simulated downhole drilling condition. Analyses that neglect the naturally fractured nature of the shale fall short in simulating wellbore instability since they predicted a narrower mud-weight window for the drilling operation, while the chemical and mud salinity effects can be utilized as a stabilizing factor.
Identification and Characterization of High-Conductive Layers in Waterfloods
Authors: Kabir C. S. , Izgec B.
Published: October 2009

This study expands upon the use of modified-Hall analysis to discern the characteristics of a high-permeability channel. Briefly, the modified-Hall plot uses three curves involving improved Hall-integral and the two derivatives, analytic and numeric. Ordinarily, the derivative curves overlay on the integral curve during matrix injection, but separates lower when fracturing occurs. This work presents a method to identify and characterize high-conductive layers or channels between injector and producer pairs with the modified-Hall analysis. The distance separating the integral and derivative curves provides the required information to quantify channel properties. A simple analytical solution is presented for transforming the separation distance into channel permeability-thickness product.

The analytic derivative is based on the radial-flow-pattern assumption and the numeric derivative is correlated to the pressure response. Therefore, a comparison of these two curves reveals clues about the maturity of a waterflood at a given time. Several simulated examples verified the channel-property-estimation algorithm and identified the distinctive derivative signatures for channeling and fracturing situations. This methodology is also useful for identification of wormhole propagation during sand production in unconsolidated formations.
Use of Steady-State Multiphase Models to Approximate Transient Events
Authors: Fan Yongqian , Danielson Thomas J.
Published: October 2009

Transient multiphase pipeline models have found wide use in upstream oil and gas production. Such models have been successfully used to estimate such transient events as flow ramp-up, pigging, and terrain slugging. However, it is not often appreciated how much can be done using steady-state multiphase models. Such models – along with minimal additional analysis – can be used to estimate liquid flow rate, liquid hold-up and pressure drop changes that are equivalent to full transient simulations. The focus of this paper will be on the use of steady-state models to estimate transient behavior, including estimates of ramp-up and pigging slugs, as well as terrain slugging severity (including slug size and frequency).
The Geared Centrifugal Pump: A New High-Volume Lift System
Authors: Patterson John C. , Morrow William B. , Berry Michael R.
Published: October 2009

The Geared Centrifugal Pump (GCP) is a high volume artificial lift system consisting of a progressive cavity pump style rotating rod string driving a bottom intake electric submersible pump (ESP) style multi-stage centrifugal pump via a downhole speed increasing transmission. The heart of the system is the unique transmission that utilizes a novel gearing configuration that allows high torque and power. The GCP provides the high volume lift of an ESP but with better gas handling, simpler operation, and lower capital and operating costs. Additionally, since all downhole components are mechanical the GCP can operate effectively at very high temperatures.
Deep Electrical Images, Geosignal and Real Time Inversion Help Guide Steering Decisions
Authors: Seifert Douglas J. , Al Dossary Salem , Chemali Roland , Bittar Michael , Lotfy Amr , Pitcher Jason , Bayrakdar Mohammed
Published: October 2009

Early production, as well as ultimate oil and gas recovery, from a reservoir often depend on the timeliness and the accuracy of geosteering decisions. Exiting the reservoir during drilling results in costly nonproductive intervals. Even staying within the reservoir but in a nonoptimal location eventually leads to early water breakthrough while leaving behind valuable oil. In recent years, azimuthal deep resistivity measurements have been recognized as beneficial to real-time steering decisions. Because of their deep investigation, azimuthal deep resistivity measurements anticipate exits from the reservoir well before such events occur. In addition, their azimuthal sensitivity clearly points to the direction of preferred evasive actions.

Azimuthal wave resistivity measurements take on multiple embodiments with multiple characteristics and multiple depths of investigation. The best results are achieved by jointly interpreting several of these measurements according to workflows that are specific to the particular applications. In the simplest cases, the up-down resistivity curves exhibit an unexpected behavior that has proven valuable both to petrophysicists and to geosteering specialists. When approaching conductive overlaying shale, for example, the up-curve tends to read the resistivity of the reservoir and the down-curve exhibits amplified horns beneficial to reservoir navigation. Resistivity images feature bright spots whose progression with increasing depth of investigation facilitates the avoidance of unwanted boundaries. A new measurement, designated as a geosignal, features strong lateral sensitivity. The geosignal from the deepest spacing is best suited to provide an early indication of the approaching boundary, with a near-exponential dependence on the distance to boundary. Quantitative inversion based on a subset of the azimuthal resistivity logs and the use of limited local knowledge helps to quantify the distance to the reservoir boundaries and their rate of approach.

This paper presents some of the most commonly used interpretation methods are demonstrated on computer models, and then applied to various wells, with applications varying from thick reservoirs to interbedded sand-shale sequences.
Streamline-Based Simulation of Non-Newtonian Polymer Flooding
Authors: AlSofi Abdulkareem M , Blunt Martin J
Published: October 2009

Current commercial simulators for polymer flooding often make physical assumptions that are not consistent with available experimental data and pore-scale modeling predictions. This may lead to overly optimistic recovery predictions for shear-thinning polymers, while overlooking the potential advantages of reducing flow rate or using shear-thickening agents.

We develop a streamline-based simulator that overcomes these limitations and demonstrate how it can be used to design polymer flooding projects. The simulator implements an iterative approach to solve the pressure field since the pressure depends on the aqueous phase viscosity which in turn – for non-Newtonian fluids – depends on shear stress and hence the pressure gradients. This is in contrast to the common approach in commercial simulators where this viscosity-pressure interdependence is ignored, leading to over-estimation of sweep efficiency. Furthermore, in the simulator, non-Newtonian viscosities are defined to be cell-centered while current simulators use a face-approach thereby over-predicting viscosities as well as the stability of the displacing fronts. In addition, we use a physically-based rheological model where non-Newtonian viscosities in two-phase flow are taken at actual effective stresses instead of single-phase equivalents.

To validate the simulator, we construct one-dimensional analytical solutions for waterflooding with a non-Newtonian fluid. We then compare our results to those from commercial simulators. We discuss the significance of current assumptions to demonstrate the impact of non-Newtonian behavior on sweep efficiency and recovery.
A New Pressure/Rate Deconvolution Algorithm to Analyze Wireline Formation Tester and Well-Test Data
Authors: Pimonov Evgeny , Ayan Cosan , Onur Mustafa , Kuchuk Fikri
Published: October 2009

The deconvolved pressure change and its natural-logarithmic time (or Bourdet) derivative are very important for wellbore/reservoir system identification in pressure transient interpretation because they represent the constant-rate drawdown response of the system. In recent years, the use of pressure/rate deconvolution has increased considerably due to significant improvement of the mathematical algorithms. In this paper, we present a robust deconvolution algorithm based on a weighted Euclidean norm in the Tikhonov regularized objective function so that one can assign weights to individual pressure and rate measurement points, and thus define different error estimates for different sections of the data. Incorporating such features into the deconvolution algorithm is very useful to mitigate the effects of unreliable pressure and rate measurements and the sections of the data not obviously consistent with the wellbore/reservoir model. In the deconvolution algorithm, the Levenberg-Marquardt method with a restricted step procedure is used for the minimization of the objective function.

We present several applications of the new algorithm using real field pressure/rate transient data sets. In addition to well test data, we apply the algorithm to wireline formation-tester pressure transients which are usually also referred to as Interval Pressure Transient Tests (IPTT). The examples include data with cleanup effects as well as an IPTT test, followed by a conventional Drill Stem Test (DST). To the best of our knowledge, applications of deconvolution to wireline formation-tester pressure transients have been limited to a single publication before. Hence, the deconvolution algorithm and the results in this paper will be useful in designing and interpreting wireline formation tester pressure transients in addition to pressure transient well tests.
Gas Storage Facility Design Under Uncertainty
Authors: Ettehadtavakkol Amin , Jablonowski Christopher , Lake Larry W.
Published: October 2009

During the screening and concept selection stages of gas storage projects, many estimates are required to value competing projects and development concepts. These estimates are important because they influence which projects are selected and which concept proceeds into detailed engineering. In most cases, there is uncertainty in all of the estimates. As a result, operators are faced with the complex problem of determining the optimal design. A systematic uncertainty analysis can help operators solve this problem and make better decisions. Ideally, the uncertainty analysis is comprehensive and includes all uncertain variables, and simultaneously accounts for reservoir behavior, facility options, and economic objectives. This paper proposes and demonstrates a workflow and integrated optimization model for uncertainty analysis in gas storage. The optimization model is fast-solving and eliminates most constraints on the scope of the uncertainty analysis. Using this or similar workflows and models should facilitate analysis and communication of results within the project team and with other stakeholders.
Field Test Results of a New Neutron-Induced Gamma-Ray Spectroscopy Geochemical Logging Tool
Authors: Galford James , Quirein John , Shannon Scott , Truax Jerome , Witkowsky James
Published: October 2009

A new geochemical logging tool has been developed to provide measurements of elements important to the mineralogical analysis of rock formations and geochemical stratigraphy. The measurement system uses a chemical americium-beryllium neutron source to introduce moderate energy neutrons into the surrounding environment. These neutrons lose energy through scattering reactions and are eventually absorbed by materials in the borehole, the formation and the tool itself. The scattering and absorption reactions cause various elements among the atoms in the surrounding materials to emit gamma rays which have characteristic energies. Emitted gamma ray spectra are detected and recorded using a large bismuth germanate scintillation detector coupled to a high-efficiency photomultiplier and pulse-height analyzer.

The recorded 256-channel spectra are analyzed to derive individual contributions, or elemental yields, arising from neutron capture reactions involving hydrogen, silicon, calcium, iron, sulfur, potassium, titanium, gadolinium, magnesium, aluminum and chlorine. The spectral analysis is performed with a constrained, weighted least-squares solver to ensure physically meaningful solutions are obtained for the elemental yields. Additional signals from inelastic neutron reactions with oxygen, carbon, silicon, calcium, and iron are treated separately in the spectral fitting process.

The paper discusses several subjects including basic operation of the tool, derivation of characteristic elemental spectral responses, processing of the recorded spectra to obtain elemental yields and the conversion to elemental weight fractions for downstream formation mineralogy evaluations. Example logs from initial field tests are presented to demonstrate tool performance under various borehole conditions and lithologic environments including sandstone and carbonate reservoirs as well as organic shales.
First 4.5-in Through-Tubing ESP with Downhole Wet Connect
Authors: Patterson John C. , Head Philip , Moulsdale Peter
Published: October 2009

Artificial Lift Company Ltd. (ALC) and ConocoPhillips Company in 2004 initiated a 5 year development program to have a fully deployed wire-line through tubing electric submersible pump (TTESP) with a down hole 3 phase electrical wet connector.

ConocoPhillips Alaska had immediate applications for this technology in its Alaska business unit, West Sak asset. The wells in this asset are multi lateral and suffer from large amounts of sand production which settles in the mother bore restricting production flow to the ESP. Historically, a Rig would be required to pull the tubing and ESP equipment to allow access for wellbore intervention. ConocoPhillips has had 10 years of experience with wireline pumps1 which allowed pump replacement of sanded pumps but did not provide for rigless cleanout of the casing below the ESP. The ability to pull the entire ESP through 4.5" tubing providing an unobstructed tubing string for placement of lateral re-entry modules and to conduct coiled tubing cleanouts of sand in the casing was highly desireable.

This was also aligned with ALC's objective which was to make the system compatible with the most common wellbore architecture.
Oil-Recovery Predictions for Surfactant Polymer Flooding
Authors: Rai Khyati , Johns Russell T. , Lake Larry W. , Delshad Mojdeh
Published: October 2009

There is increasing interest in surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding because of the need to in-crease oil production from depleted and water flooded reservoirs. Prediction of oil recovery from SP flooding, however, is complex and time consuming. Thus, a quick and easy method is needed to screen reservoirs for potential SP floods. This paper presents a scaling model that is capable of producing reliable estimates of oil recovery for an SP flood using a simple spreadsheet calculation. The model is also useful for initial SP design.

We present key dimensionless groups that control recovery for a SP flood. The proper physics for SP floods including the optimal salinity in the three-phase region and the trapping number for residual oil saturation determination has been incorporated. Based on these groups, a Box-Behnken experimental design is performed to generate response surface fits for oil recovery prediction at dimensionless times. The response surfaces derived can be used to estimate the oil recovery potential for any given reservoir and are ideal for screening large databases of reservoirs to identify the most attractive chemical flooding candidates. The response function can also be used for proper design of key parameters for SP and ASP flooding. Our model will aid engineers to understand how key parameters affect oil recovery without performing time consuming chemical simulations.

This is the first time that dimensionless groups for SP flooding have been derived comprehensively to obtain a response function of oil recovery as a function of dimensionless groups.
Improved Accuracy in the Measurement of Downhole In-situ Fluid Density
Authors: Gao Li , Van Zuilekom Tony , Pelletier Mickey , Proett Mark , Rourke Marvin , Palmer Richard , da Silva Andre Santos , Al-Hajari A. A.
Published: October 2009

New sensors have been developed for measuring in-situ fluid density that are based on the natural vibration of a structural member in contact with fluids being sampled using a wireline pumpout formation tester. Typically, a fluid-conveying tube is driven to its natural frequency and the frequency changes with fluid density. This design has the potential to greatly enhance the downhole fluid density measurement capability. However, the physical characterization and subsequent calibration of the sensor had to be proven for the harsher downhole environment. Although the principle for the vibrating density sensor is simple, a long list of factors, such as temperature, pressure, and tension, directly or indirectly affect the response of the sensor.

Experimental correlations are typically used to calibrate this type of sensor. However, in this paper, we systemically study all of these factors and derive a differential equation that fully describes the physics of the vibrating tube densitometer based entirely on first principles. This is followed by the solution of the equation and its subsequent application to laboratory test results as part of the sensor calibration process. Comparisons between theoretically predicted density values for various fluids and their known fluid density values show this method to be more robust than previous correlations methods. An accuracy of better than +/- 0.002 gm/cm3 over the pressure range of 0 to 20,000 psi and a temperature range of 75 to 350°F under controlled conditions is achievable. The resolution of the sensor can also be better than 0.001 gm/cm3. Experimental results and field examples are presented to demonstrate the accuracy and resolution of the sensor.
New Inflow Performance Relationship for Solution-Gas Drive Oil Reservoirs
Authors: Elias Mohamed , El-banbi H. Ahmed , Fattah K. A. , El-Tayeb El-Sayed Ahmed Mohamed
Published: October 2009

The Inflow Performance Relationship (IPR) describes the behavior of the well's flowing pressure and production rate, which is an important tool in understanding the reservoir/well behavior and quantifying the production rate. The IPR is often required for designing well completion, optimizing well production, nodal analysis calculations, and designing artificial lift. Different IPR correlations exist today in the petroleum industry with the most commonly used models are that of Vogel's and Fetkovitch's. In addition to few analytical correlations, that usually suffers from limited applicability.

In this work, a new model to predict the IPR curve was developed, using a new correlation that accurately describes the behavior the oil mobility as a function of the average reservoir pressure. This new correlation was obtained using 47 actual field cases in addition to several simulated tests.

After the development of the new model, its validity was tested by comparing its accuracy with that of the most common IPR models such as Vogel, Fetkovitch, Wiggins, and Sukarno models. Twelve field cases were used for this comparison. The results of this comparison showed that: the new developed model gave the best accuracy with an average absolute error of 6.6 %, while the other common models are ranked, according to their accuracy in the following order to be Fetkovich, Sukarno, Vogel, and Wiggins, with average absolute errors of 7 %, 12.1 %, 13.7 %, and 15.7 respectively.

The new developed IPR model is simple in application, covers wide range of reservoir parameters, and requires only one test point. Therefore, it provides a considerable advantage compared to the multipoint test method of Fetkovich. Moreover, due to its accuracy and simplicity, the new IPR provides a considerable advantage compared to the widely used method of Vogel.
Corrosion Inhibition of Low-Alloy Steels in Brine With Highly Oxygenated Nitrogen Membrane Gas for Underbalanced Drilling Applications
Authors: Mcnealy Richard , Hausler Rudy , Tabinor Matthew
Published: October 2009

Residual oxygen in membrane generated nitrogen, when commingled with potassium or sodium chloride drilling brines for underbalanced drilling (UBD) applications, is known to be very corrosive to drill pipe, casing and tubing. Commercial chemical inhibitors are routinely applied in such applications but supporting laboratory test data in the literature often fail to represent actual downhole environments.

The corrosion rate data from case study wells has limited value due to available locations and technology for measurement within drilling process flow loops. The test protocol discussed here and corresponding results provide for more realistic evaluation of inhibitor effectiveness and suggest a mechanism for corrosion inhibition.

The tests were conducted in stages intended to first establish the baseline corrosive behavior of low alloy steel in oxygenated brine with and without pH control by means of buffering agents. Subsequent tests focused on the effect of corrosion inhibitor concentrations and other additives. The results of the test program indicated that a combination of conditions resulted in significant inhibition of low alloy steel against oxygen corrosion, and is associated with the formation of surface film containing phosphorus. Corrosion rates as low as 50mpy without pitting were achieved, compared with 900mpy with significant scaling for uninhibited oxygenated brine.

This paper describes the development of conditions necessary to create a stable protective film in oxygenated brine without the formation of copious corrosion products known to present problems in UBD operations. The test protocol used herein suggests a method for qualifying the performance of candidate inhibitor formulations for specific UBD design conditions.
Laboratory and Field Scale Analysis of Steam Over Solvent Injection in Fractured Reservoirs (SOS-FR) for Heavy-Oil Recovery
Authors: Al Bahlani Al Muatasim , Babadagli Tayfun
Published: October 2009

Tapping heavy-oil from fractured carbonates is a real challenge due to unfavorable rock and reservoir characteristics. We introduced a new technique called Steam-Over-Solvent in Fractured Reservoirs (SOS-FR) for efficient heavy-oil recovery from fractured reservoirs, more specifically carbonates. The process consists of cyclical injection of steam and solvent in the following manner: Phase-1: Steam injection to heat up the matrix and recover oil mainly by thermal expansion, Phase-2: Solvent injection to produce matrix oil through diffusion-imbibition-drainage processes, and Phase-3: Steam injection to retrieve injected solvent and recover more heavy-oil. Our preliminary experiments under static (SPE 117626) and dynamic (SPE 123568) conditions showed that, under very unfavorable conditions (oil-wet carbonate, ~4,500 cp crude), oil recovery at the end of Phase-3 could be as high as 85-90% OOIP with 80-85% solvent retrieval.

This paper presents numerical modeling of the dynamic experiments and an upscaling study for reservoir size matrix. Heptane was selected as the solvent to inject through a single-matrix/single-fracture oil-wet Berea sandstones saturated with ~4,500 cp oil. The experimental results were matched to a single matrix/single fracture numerical model and parameters needed for larger scale simulation (matrix-fracture interaction parameters such as thermal diffusion, solvent diffusion and dispersion coefficients) were obtained. The main focus was the matrix size and first an up-scaling study to field conditions was performed.

Specific observations and conclusions as to the applicability of this technique in the field effectively were reported. It is hoped this new technique will be an alternative for tapping heavy matrix oil from oil-wet, fractured, deep, carbonate fields.
Hostile Formation Testing Advances and Lessons Learned
Authors: Van Zuilekom Anthony , Rourke Marvin
Published: October 2009

Exploration and development wells are moving toward increasingly deep and hot reservoirs, which require a new generation of hostile wireline formation tester (HWFT) tools. This paper addresses both a first generation of hostile HWFT and a next generation formation testing tool that will operate in reservoirs as hot as 450°F and at 30,000 psi pressure.

The first generation of hostile sequential formation testing (HSFT) tools was introduced in 2002 (Rourke and Powell 2006). A wealth of experience collecting pressure measurements and fluid samples in formations as hot as 408°F has been accumulated since the first generation tool was introduced. Since 2002, the practice of obtaining of pressure data and fluid samples has evolved from a rarely performed service to a routinely performed service. Tool hardware and operations procedures have incorporated new techniques, which have resulted high reliability and low fishing rates. Many lessons were learned along the way. The next generation of hostile formation tester tools will incorporate the lessons learned from the first generation into its design to extend the pressure testing capabilities and to move toward the ability to acquire (PVT) quality samples and fluid identification (F-ID) in these difficult and increasingly hostile conditions.

Past HWFT experiences are used to illustrate the best practices for high pressure, high temperature (HPHT) testing. Success rates are tracked to demonstrate how the improvements have led to successful testing in progressively more hostile conditions. Conclusions are drawn regarding the future of HWFT testing and how the new technologies that are anticipated for these tools will continue to extend their capabilities.
Fracture Characterization and Dynamic Modeling in a Brownfield Carbonate Reservoir
Authors: Biswas Deepankar , Cron James W.
Published: October 2009

Understanding production behavior particularly from fractured carbonates has always been a challenge. The difficulty stems from the secondary porosity and permeability developments in carbonates in conjunction with the seemingly haphazard fracture presence in the midst of rapid and erratic facies changes sometimes within short distances. To make matters worse the spatial connectivity of these fractures complicates completion, pressure maintenance and improving sweep strategies. Therefore it is paramount to understand and characterize the fractured conduits and account for their importance in the overall development of the field. This paper discusses a systematic step-by-step methodology to build a geologic realization for a fractured reservoir and conduct dynamic simulations to calibrate and forecast various development scenarios.

The methodology encompasses geo-scientific work, engineering analysis, production diagnostics and reservoir simulation. Classic clustering analysis is used to augment results of production diagnostics to capture the effects of fracture dominated flow. Further, material balance utilizes early production and pressure history, during both undersaturated and saturated conditions, to provide bounds of in-place fluids. Petrophysical work analyzes available well logs to obtain matrix attributes and classify reservoir and non-reservoir types. The static model devises empirical transforms to distinguish various facies types. The facies types are stochastically populated in the inter-well region. A possible realization of the reservoir based on total-property approach is constructed. The reservoir model is then calibrated based on 25 years of production and some pressure history. Finally, various development scenarios are investigated.

The observations of clustering analysis is discussed and tied to the production behavior. The insights gained are shown to enhance calibration process. The integrated approach is demonstrated to unlock various uncertainties about in-place and recoverable reserves.

Significant contributions are: Clustering analysis4 in conjunction with production diagnostics to reveal the nature of the fracturesWeigh various development scenarios to unlock the myths of stereotypical development patternA way to learn more about the reservoir architecture and resident fluid movements to screen for upside potential
Improved Kick Management During MPD by Real-Time Pore-Pressure Estimation
Authors: Gravdal Jan Einar , Nikolaou Michael , Breyholtz Øyvind , Carlsen Liv A.
Published: October 2009

Pressure maintenance within safe bounds and minimization of influx of fluids from the formation to the well during a kick are basic concerns of well control. Managed Pressure Drilling (MPD) offers improved capabilities over conventional well control methods to address these concerns. In this work we develop a methodology that capitalizes on the improved access to down-hole measurements offered by wired drill pipe telemetry, to maintain pressure within desired bounds during kick management. The objective of this methodology is to improve MPD by reducing non productive time, reducing formation damage and optimizing operational limits for the annular back pressure choke manifold.

The proposed methodology estimates formation pore pressure automatically based on real-time measurements when a gas kick is taken during MPD. The methodology relies on the characteristics of the pressure build-up curve. Implementation of the methodology presumes the availability of standard MPD equipment for automatic annular back pressure control.

A representative North-Sea well is used as test case geometry and an advanced hydraulics model is used as a virtual well in computer simulations that provide the basis for the presented results.

The proposed methodology is demonstrated to both maintain pressure within desirable bounds and reduce formation fluid influx during a kick and thereby prevent the risk of hole stability problems and the cost associated with non-productive time.
Integration of Well Test Pressure Data Into Heterogeneous Geological Reservoir Models
Authors: Li Gaoming , Han Mei , Banerjee R. , Reynolds A. C.
Published: October 2009

This paper presents the application of the ensemble Kalman filter (EnKF) method to the integration of well test data into heterogeneous reservoir models generated from geological and geophysical data. EnKF does not require computing the gradient of an objective function, and hence can be applied easily with any reservoir simulator, and more importantly, is far more efficient than a gradient-based history matching procedure when the forward model is represented by a reservoir simulator. In the procedure for integrating pressure transient data considered here, the static geological/geophysical data are assumed to be encapsulated in a multivariate probability density function characterized by a prior mean and covariance for the joint distribution of the porosity and permeability fields. As the prior mean of the property fields obtained from the core and log data can sometimes be erroneous, a partially doubly stochastic model is applied to account for the uncertainty of the prior mean. In the doubly stochastic model, a correction to the prior mean is adjusted together with the heterogeneous field during history matching. The method is tested with synthetic heterogeneous single-layer and two-layer reservoirs. Excellent data matches are obtained with EnKF in a small fraction of the time that would be required for a gradient-based history-matching process and the observed data fall within the uncertainty bounds of the ensemble data predictions. In the layered reservoir case, the uncertainty in rock property fields is further reduced by integration of production log data (layer flow rates). We show that problems of statistical inconsistency and poor data matches that are sometimes encountered when matching production data with EnKF do not occur when matching pressure data with the EnKF implementation used here. This undoubtedly occurs because the dynamical system (reservoir simulator equations) is much more nearly linear for the single-phase flow problems considered here than for multiphase flow cases.
Prediction of Slug Frequency for High Viscosity Oils in Horizontal Pipes
Authors: Gokcal B. , Al-Sarkhi A. S. , Sarica C. , Al-Safran E. M.
Published: October 2009

Slug frequency is defined as the number of slugs passing at a specific point along a pipeline over a certain period of time. Most experimental studies related to slug frequency in the literature were conducted using air and water. Data with a viscous liquid phase are scarce. Knowledge of the effect of liquid viscosity on slug flow is crucial to size pipelines and design pre-process equipment. In this study, the effects of high oil viscosity on slug frequency for horizontal pipes are experimentally investigated. The experiments are performed at oil viscosities between 0.181 and 0.589 Pa·s in a horizontal pipe. Experimental results are compared with the existing slug frequency correlations. Experimental observations reveal that slug frequency appears to be a strong function of liquid viscosity. However, existing slug frequency closure models do not show any explicit dependency on liquid viscosity. A closure model taking into account viscosity effects for horizontal pipes on slug frequency is proposed. The proposed slug frequency model is compared against published data. The comparison of proposed closure model against limited published data shows that it is a better alternative than existing correlations for high viscosity oils. The proposed slug frequency closure model can improve the performance of the existing mechanistic models for high viscosity oil applications.
Analytic Investigation of Convection During Conduction Heating of a Heavy-Oil Reservoir
Authors: Lawal Kazeem A. , Vesovic Velisa
Published: October 2009

The assumption of constant temperature is often valid for the operation and analysis of most conventional oil reservoirs; however the average behaviour of reservoirs exposed to thermal flooding is non-isothermal. In addition to being non-isothermal, heated reservoirs are characterised by non-uniform temperature distribution. Where the heating mechanism is conduction, most analyses ignore convection (including natural convection) in the overall heat balance. However, the induced temperature gradient affects fluid properties (especially viscosity and density) and their spatial distribution.

In this paper, possible buoyancy-induced natural convection is investigated by simulating one-dimensional vertical temperature profiles of a semi-infinite reservoir column, fully saturated with undersaturated heavy oil, subjected to conduction heating from the bottom. Using a realistic temperature dependence of the density and viscosity of typical Athabasca bitumen, vertical distributions of in-situ oil density, velocity and Nusselt number consistent with the induced temperature gradient are established. The simulation results indicate that at any time, oil density increases vertically away from the heat source, a condition that is gravitationally unstable, with a potential for fluid-redistribution, triggering convection. In this study, the magnitude of a Nusselt number is used as a proxy for the relative importance of natural convection. Although it is shown that free convection can be important, its significance depends on the duration of heating as well as rock and fluid properties. Consequently, we argue that the convective heat-transfer, in addition to temperature and time-dependent variations of oil density and viscosity, should be considered in realistic models of thermal recovery of heavy oil, even if the heating philosophy is "apparently" conduction.
Produced Water Separation at Unmanned Offshore Wellhead Platform: A Concept Report
Authors: Gupta Anil Kumar , Rai Ramashish , Kumar Ajit , Asija Narendra , Soni Dheeraj
Published: October 2009

In the mature producing offshore fields, managing water production is an important and critical aspect of the oil and gas production. Fields where topside processing facility has reached to its maximum handling capacity, installation of additional equipments require a new approach. Taking a clue from the latest profiles of Indian Offshore Assets which suggest increase in water cut of the order of 70% presently and rising up to 92% by 2030 overloading the process (separation and produced water conditioning) facilities at Process Platforms. This is where project on produced water separation at offshore wellhead platforms was taken up. Water separation at wellhead can be used to: Increase the oil production rate in a pipeline with a given diameterReduce capacity constraint at separator inletDevelop compact and low weight facilities for marginal topsides

With aim to minimize produced water handling at downstream of Wellhead Platform i.e. at process platform, free water is to be knocked out at WHP with ❖Minimum Wellfluid pressure reduction❖Minimum Floor Space❖Minimum Interference❖Maximum reliability

Recent developments have made possible separation system meeting strict requirements with respect to both performance and reliability. There are separators operating in subsea environment removing produced water from Wellfluid with desired results. In view of this, the present condition of Mumbai offshore field necessitates the deployment of such techniques in the ageing Mumbai High field as well.

This study focuses on produced water separation at offshore WHP and examines the factors affecting separation at unmanned WHP. The study also analyzes the impact of Produce Water Separation at WHP. The possible impacts envisaged are flow assurance, reduced backpressure on wells, wells deliverability, capacity constraint at the Separator inlet and Liquid handling at PWC system of Process Platform.
Laboratory Modelling of Equipment Erosion by Sand Particles
Authors: Graham Lachlan , Wong Chong Y. , Lester Daniel , Wu Jie
Published: October 2009

Impact by sand particles entrained in gas or oil product streams from down-hole well completions often causes erosive damage to the surface of sand filtration screens, heat exchangers, pipes, pipe bends, valves, gas compressors and other equipment. It is of major interest to develop designs to minimise the erosion damage. Erosion is often found to be unevenly distributed, for example erosion in a pipe elbow. Localized deep material loss or holing can lead to functional failure even though other areas of the component surface may be still undamaged. It was found that component design/geometry could often be modified to alter the flow field and even-out the erosion distribution, thus reducing the localized high erosion rate and extending the equipment service life. The optimization process can be most effectively carried out with assistance from erosion flow modelling. The objective of this paper is to describe the latest erosion flow modelling technique used at CSIRO, Australia. The technique consists of a combined laboratory physical modelling and computational fluid dynamics (CFD) approach. The physical modelling employs a paint modelling technique to illustrate the erosion patterns and advanced metrology for quantitative erosion measurements. Both of these data sets are also used to validate and improve CFD erosion modelling. The paper will show a series of case studies of erosion prediction and an example of erosion reduction through geometrical modifications with the materials used unchanged.
Minimum Miscibility Pressure Investigations for a Gas Injection EOR Project in Al Shaheen Field, Offshore Qatar
Authors: Mogensen K. , Hood P. , Lindeloff N. , Frank S. , Noman R.
Published: October 2009

Gas injection as an EOR method is being considered for the giant Al Shaheen field, located offshore Qatar. The field is characterized by large lateral variations in fluid properties; the oil gravity ranges from 16 to 38 °API and significant variations in initial GOR and saturation pressure are observed.

An extensive experimental program aimed at establishing the miscibility behaviour for this complex fluid system has been performed. Experiments included a range of gas injection tests such as swelling and multi-contact miscibility tests, enrichment studies and slimtube measurements. The miscibility behaviour across the range of oil gravities has been very well captured with a single equation of state (EOS) model, as described by Lindeloff et al. (2008).

Slimtube measurements are the preferred method for establishing minimum miscibility pressures experimentally as condensing/vaporizing effects can be captured in this setup. The physical dispersion of the slimtube was characterized by a specially designed experiment using first-contact miscible (FCM) fluids. The results of the FCM experiments were used to determine the degree of numerical dispersion required in a 1D slimtube simulation model to match the measured data. An extrapolation towards an infinite number of cells was then performed to estimate the dispersion-free minimum miscibility pressure (MMP) from the slimtube experiments conducted on live reservoir oil using carbon dioxide as injection gas.

In addition to the slimtube simulations, several algorithms for estimating the minimum miscibility pressure have been compared; some are empirical correlations, others are based on analytical gas injection theory using the method of characteristics (MOC) limiting tie-line method and the last one relies on a mixing-cell approach. The advantages and drawbacks of each approach are discussed, and the results are compared to laboratory data. In general, there is a very large spread in predicted MMP using carbon dioxide as injection gas. Empirical correlations generally overpredict the MMP for light oils and underestimate the MMP for heavy oils. Various key tie-line methods using the same tuned EOS model provide very different estimates of the MMP and some of them exhibit convergence problems. The results of the present work suggest that the mixing-cell model provides the most robust estimate of MMP over a large range of oil compositions, subject to EOS description. In essence, there is currently no prediction method that can replace the slimtube experiments.
A Comprehensive Methodology to Avoid and Remediate Drilling Problems by Real Time PWD Data Interpretation
Authors: Gandelman R. A. , Martins A. L. , Teixeira G. T. , Waldmann A. T. A. , Mari A. D. , Rezende M. S. C. , Aragão A. F. L.
Published: October 2009

Drilling offshore oilwells is a very expensive and complex job, in which all efforts must be spent to keep the annular pressure between a minimum (pore pressure) and a maximum pressure (frac pressure). A lot has been invested in downhole sensors and data transmission systems but there is a common sense in the industry that very little is available in real time data interpretation. The correct interpretation of PWD (Pressure While Drilling) data is a very powerful tool to identify undesired phenomena. The anticipation and remediation of potential hole problems is an ultimate goal of most real time measurement devices installed on drilling rigs. The accurate quantification of the phenomena that impact bottom hole pressures is a must on anticipation operational problems. This paper presents a comprehensive methodology to accurately quantify some of the most common phenomena that occur during the drilling job. Transient modeling, pattern recognition and AI strategies were considered. The final goal is the development of a real time computational tool to interpret the operational parameters, identify and remediate problems, reducing risks, time and costs.

Examples of problems detection (such as cuttings excessive accumulation, kicks, wash outs, hydraulic packers, instability related issues, etc) will be addressed. Besides, the impact of remedial actions on downhole pressures and solids concentration profiles will be also detailed.