bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimized Nuclear Logging for Fast Drilling
Authors: Helgesen T. B. , Jonsbråten F. , Pepper C. F.
Published: December 2007

Slow data acquisition rates have generally not been a problem for LWD due to moderate logging speeds while drilling. With the recent advances in drilling technology, high logging speeds impact the log quality and, in particular, the nuclear logs. When a detector passes a longer interval of rock for each acquisition period, its vertical resolution is degraded. For azimuthally sectored data, this is even more of an issue, as bedding features within a sample period get blurred.

The objective of the study is to develop a methodology to optimize LWD data acquisition, enabling the E&P company to drill faster and meet its data acquisition objectives.

This paper describes analytical simulations and field tests performed to optimize data acquisition for fast drilling in the Norwegian North Sea. Optimization of data acquisition is described as addressing the trade-off between low data density with accurate measurements versus high data density with less accurate measurements.

Based on nuclear logs acquired in adjacent wells, bed contrasts were defined for zones of interest. Modeling was done to define the minimum acquisition time needed to detect the defined contrasts. Telemetry was designed with adequate resolution for geo-steering, thus saving bandwidth. The impact on memory data accuracy caused by faster acquisition rates was modeled to check feasibility. Field tests were performed to validate the modeling results.

Real-time telemetry accuracy proved adequate and the improved data density provided better definition of bedding features versus standard setup. Memory data contained better vertical resolution, further enhancing bedding features, while maintaining the required accuracy. Understanding all end users' specific data quality requirements is key to an acceptable compromise.

Applying this methodology in the planning phase for other wells ensures all stake holders' needs are considered, and aids the overall understanding of LWD acquisition limitations and highlights the possibilities.
Analysis of MWD Pressure Data During Turbulent Flow and Modeling Implications
Authors: Jachnik R. P. , May R.
Published: December 2007

During the drilling of deviated wells it has been recognized that the drill string can be in some eccentric condition and that this has an effect on annular pressure loss. Previous attempts to quantify how much of the drill string and to what degree of eccentricity it is in within various hole sections have often relied on general assumptions such as fully or partly eccentric. This paper describes a method to more accurately quantify the amount of eccentricity throughout each hole section by use of torque and drag modeling and derivation of a side force plot. This details whether pipe is lying on the side of the borehole (top or bottom) or is crossing over from one side to the other. The pipe body is assumed to be stiff between each tool joint. A simple geometric relationship between drill pipe tool joints and pipe body defines the eccentricity. The length per hole section and geometric eccentricity can then be used either in calculating pressure loss more accurately while in laminar flow or by use of empirical factors to calculate pressure loss during turbulent flow should this be a requirement.

Field data was obtained at the end of a horizontal well drilled in the Norwegian North Sea and input into two propreitary modeling packages. One, a finite element program confirmed the suitability of using the side force plot data derived from Torque and Drag modeling. Hydraulic pressure loss calculations with the second program confirmed the overprediction of annular pressure loss by 20% in this field example if eccentricity is not considered. Using the determined eccentricity and an equation in the literature that applies a factor to concentric pressure loss values it was possible to calculate annular pressure loss values that were within 3% of the measured MWD values.
A Facies-Based Approach to Distribution of Petrophysical Properties in an Aeolian Sandstone Reservoir, Unayzah Formation, Saudi Arabia
Authors: Raba’a A. S. , Heine C.
Published: December 2007

Defining and distributing petrophysical reservoir property within a simulation ready geocellular model is an industrywide dilemma; the result of which has a large business impact on reservoir management decisions. The objective of this study is to develop porosity-to-permeability transforms, multiphase relative permeability and capillary pressure curves for each distinct depositional facies. The key to this process is the ability to recognize each of the four eolian facies and demonstrate that even at deep formation; the original depositional facies controls the petrophysical properties.

Through core and image-log studies, the geologist divided the reservoir into the four distinct depositional facies that comprise a "wet" eolian depositional system: dune, sand sheet, paleosol, and playa. Each facies was distributed proportionately by zone (vertically) and by region (area) in a 3D geocellular model using an object based modeling technique and a wet eolian depositional model. The dune facies is the best reservoir unit followed by sand sheet; together the dune and sand sheet comprise a high proportion of the reservoir gross thickness. Conventional and special core analysis measurements were conducted on hundreds of core samples from three gas wells. The core data were thoroughly evaluated for pertophysical properties, and then grouped by depositional facies. Porosity-to-permeability transforms, multiphase dynamic relative permeability and capillary pressure were derived for each facies. The reservoir properties were then geostatistically distributed within each facies object using the facies and zone specific transforms.

Results showed a quantifiable porosity-to-permeability transform, and corresponding capillary pressure and condensate-gas relative permeability for each depositional facies in the reservoir. This paper shows that by grouping the reservoir into recognizable depositional faceis has significantly enhanced the distribution of reservoir and fluid properties, which were incorporated into a compositional model. This will result in a dependable fluid-flow model that will support investment, reservoir development and reservoir management decisions.
Applying Downhole Fluid Analysis and Wireline-Formation-Testing Techniques in Reservoir Management and Well Completion—Case Studies
Authors: Khalil M. , Maamari K. K. , Jackson R. R. , Cig K.
Published: December 2007

The Gharif and Al Khlata Formations form significant reservoirs in north-central Oman. The reservoirs are multilayered, heterogeneous and highly variable in terms of geometry, connectivity, permeability and fluid properties. Newly drilled wells often show differential pressure depletion between layers, which helps assess lateral and vertical reservoir continuity. However such complexity and reservoir heterogeneity means that conventional pressure-depth plot and pressure gradient analysis of wireline pressure data is not easy, and identification of in-situ fluid density changes can be difficult.

A significant part of formation evaluation within these reservoirs has required the application of downhole fluid analysis (DFA) and fluid identification using a pumpout wireline formation tester. The primary objectives being to obtain a measurement of formation pressures, identification of the formation fluids, capture fluid samples and determination of fluid mobility. Such information is important input for both reservoir management purposes and in optimizing the well completion strategy.

We discuss testing techniques using a modular wireline formation tester equipped with a dual packer and/or probe modules, and latest generation optical fluid analyzers. The tests usually comprise of extended pumpout, drawdown and buildup periods, during which oil-based mud filtrate contamination, and fluid composition are monitored in-situ in real time. The techniques applied include in-situ characterization of reservoir fluid type and composition, gasoil-ratio (GOR), and the use and application of fluorescence measurements.

In this contribution we compare and demonstrate the utilization of data from wireline downhole formation fluid analysis and formation tests, and also their practical application in reservoir management.. The field examples described are from wells mainly drilled with oil-based mud. We present some case studies and discuss how the results from tests conducted in different flow units in individual wells, and arealy across the field in multiple wells, have been used in reservoir management and well completion.
A Comparative Study of Recent Robust Deconvolution Algorithms for Well-Test and Production-Data Analysis
Authors: Cinar M. , Ilk D. , Onur M. , Valko P. P , Blasingame T. A.
Published: December 2007

In this work, we provide a comparative study of recently proposed deconvolution algorithms which were designed to function in the presence of reasonable levels of noise in both the rate and pressure input data. The algorithms considered for comparison are those presented by von Schroeter et al.1,2Levitan,3,4 and Ilk et al.5,6 These works offer robust solution algorithms to the long-standing deconvolution problem and make deconvolution a viable tool to well-test and production data analysis. However, there exists no comparative study revealing and discussing specific features associated with the use of each algorithm in a unified manner. We have independently reproduced the von Schroeter et al. and Levitan algorithms to assess the specific advantages and limitations of each method (as well as the Ilk et al. method), and we provide a comparative study of these algorithms using synthetic and field case examples.

Our results identify the key issues regarding the successful and practical application of each algorithm. In addition, we show that with proper care and attention in applying these methods, deconvolution can be used as an important tool for the analysis and interpretation of variable rate/pressure reservoir performance data.
Characterization of Commingled Reservoir Properties with Production Logs
Authors: Poe B. D. , Atwood W. K. , Kohring J. , Brook K.
Published: December 2007

This paper presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized deliverability performance of multi-layer commingled systems using multirate production log measurements. Both linear and non-linear systems are addressed in this paper, providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow, respectively.

Extension of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and well completion properties such as effective permeability, radial flow steady state damage /stimulation skin effect, and non-Darcy flow coefficient. In the specific case where the deliverability performance of a vertically fractured well is considered, estimates of the effective fracture half-length and average fracture conductivity may be derived from the analysis. In cases where the multirate deliverability tests are performed under boundary dominated flow conditions, conventional deliverability analysis techniques may also be employed to derive estimates of the reservoir drainage area in addition to the well and reservoir parameters that can be obtained in a transient flow analysis. Applications of the analyses reported in this paper demonstrate the use of the analyses to evaluate the inflow performance measurements of commingled multi-layer reservoirs obtained using multi-rate production logs.
Development of a Novel Delivery System for Ultralightweight Proppants in Conventional Fracturing Treatments
Authors: Ward B. , Beall B. , Cawiezel K. , Wheeler R.
Published: December 2007

With increased utilization of ultra-lightweight proppants, several operational challenges have been encountered. Blending and measurement challenges arise from the relative closeness of the specific gravity of ultra-lightweight proppants to the base fluid, rendering conventional measurement systems inadequate. The use of these ultra-lightweight proppants in slickwater fracturing is further complicated operationally because of the low proppant concentrations used; it is not uncommon to begin as low as 0.5 ppg added1.

The solution to this problem utilizes a pumpable carrier fluid to suspend the ultra-lightweight proppant (ULWP). The concentrated proppant slurry can be prepared at the district and transported to location where it can be pumped "as is", diluted with water or linear gel, or pumped as a foam2. This concept was developed from a previous project that involved offshore and remote location gravel and frac packs. This paper details the development, field testing, and job success of a new generation of ultra-lightweight proppants, utilizing this novel delivery concept in conventional fracturing treatments. This technology will allow companies to conduct fracturing operations with minimal equipment and manpower, and enable hydraulic fracturing to be conducted in small and/or remote locations. It will also allow an increased number of fracturing treatments to be completed in areas where equipment utilization is at a maximum and additional frac fleets are needed.
Geosteering Diagnosis: A New Approach to Monitor the Well Position within a 3D Geological Model
Authors: Thevoux-Chabuel H. , Fejerskov M.
Published: December 2007

With the increasing demand for more efficient drilling operations, the oil industry is searching for new ways of utilizing all data available while drilling. The integration of the realtime drilling information with data from offset wells and the reservoir model is considered of high value for accurate wellbore placement and geosteering.

This paper introduces an original methodology to better understand and analyze the well position within the subsurface and to warn the end user when predefined geological and drilling events are appearing or prognosed ahead of the drill bit. The concept is called Geosteering Diagnosis.

We identify a monitored trajectory as composed of a real-time and a project-ahead section. The bit and the MWD/LWD sensors are monitored objects attached to the trajectory. A number of targeted objects (i.e. horizons, contacts, faults, targets, planned and previous drilled wells trajectories, well and grid properties) are accessible from the 3D geological model. Rules can be defined based on the relationship between the monitored objects and any targeted objects. Various thresholds are used to identify events at the time of the drilling and alarms can be triggered on specific cases.

The Geosteering Diagnosis is applied to a production well in the North Sea. The rules are used to monitor drilling against the predefined geological model. They provide quantitative information, which can be used to either update the geological model, or take actions regarding the course of the well.
Design and Field Testing of a Truly Novel Diverting Agent
Authors: Glasbergen G. , Todd B. , Van Domelen M. , Glover M.
Published: December 2007

The success of all oilfield chemical treatments is dependent upon fluid placement efficiency. In acid-stimulation treatments, the acid should be placed so that all potentially productive intervals accept a sufficient portion of the total acid volume. The same is true for scale-inhibitor squeeze treatments. It is critical for the inhibitor to be distributed as uniformly as possible over the interval of interest.

Various diversion techniques are available to assist in alteration of the injection profile during matrix treatments. Likewise, several computer design programs are available to advise on appropriate diversion techniques and allow numerical simulation of the diversion process and efficiency. Rarely are placement models validated in the field.

Recently, a joint project was initiated to develop a novel fluid-diversion process. This project resulted in a particulate-diversion agent that has several advantages over traditional particulate diverters. Advantages include little or no environmental impact, negligible solubility at surface conditions, controlled permeability of the filter cake or perforation pack, upper temperature limit significantly higher than traditional diverting agents (excluding salt), compatibility with nearly all treatment fluids, diverter degradation at bottomhole conditions to eliminate post-treatment removal, and excellent regained permeability.

The chemical development is not the only unique and novel aspect of this joint development. An extensive field trial was conducted, incorporating multiple step-rate tests, fluid-efficiency tests, treatment-pressure matching, pressure-buildup tests, temperature surveys, and injection profiles. These tests were performed in a 226°F sandstone reservoir at approximately 11,900 ft MD. Testing was performed (1) before diversion, (2) during injection of the diverter, (3) immediately after diverter placement, and (4) finally 1-2 days later to confirm diverter degradation. The pressure-matching techniques used in this study would not be unique in proppantfracturing applications; however, the application to matrix stimulation and chemical placement techniques using both pressure matches and injection profile matches are unique and novel processes.
Navigating and Imaging in Complex Geology with Azimuthal Propagation Resistivity while Drilling
Authors: Bell C. , Hampson J. , Eadsforth P. , Chemali R. , Helgesen T. , Meyer H. , Peveto C. , Poppitt A. , Randall R. , Signorelli J. , Wang T.
Published: December 2007

Reservoir navigation with LWD resistivity has traditionally relied on matching real time measurements with ideal logs. Reservoir navigation engineers initially build one or more resistivity models including all expected resistivity boundaries such as oil-water contact, reservoir to cap rock interface, faults and unconformities. Then, during drilling, they direct the well and update the earth model by matching actual measurements with forward response model data.

Because common LWD resistivity sensors cannot differentiate between an oil-water contact approaching from below and a shale lens approaching from above or from the side, the reservoir navigation engineer fills in the missing information through expertise and local knowledge. In case of complex geology however, such as reservoirs with tilted or rotated fault blocks, multiple fluid contact levels, cross-stratification and shale intrusions, navigation becomes much more challenging and the risk of getting geologically lost is high. In recent years imaging LWD tools were introduced to help reduce the azimuthal uncertainty but they were limited to a few inches in lateral investigation.

A new azimuthally sensitive propagation resistivity tool was recently tested for reservoir navigation and formation imaging in some of the more complex reservoirs of the North Sea. In cases where standard omni directional tool responses would lead to ambiguous interpretations, the azimuthally sensitive tool provided the basis for clear geosteering advice. A new imaging algorithm helped visualize approaching beds much like modern imaging devices, but with a depth of investigation reaching several feet into the formation. At fault crossings, the azimuthally sensitive signal helped recognize the relative movement of the formations on either side of the fault. In other instances where the well was run immediately below the cap rock, deep looking azimuthal propagation anticipated the intersection by several hundred feet. Also, analysis of the detailed deep electrical images brought a more complete understanding of the subsurface.
New Closed-Loop Control System Reduces Risk in Intervention Operations
Authors: McNicol J. , McGurk M. , Pittman G. , Heisig G. , Donadieu B. , Hood J.
Published: December 2007

During well construction activities, measurement-whiledrilling (MWD) technology is applied to transmit sophisticated spatial and petrophysical data from downhole to surface. Used with advanced well construction tools such as rotary steerable systems, MWD technology has enabled complex, even tortuous, well profiles to be created and placed in the reservoir with great precision. However, even on these sophisticated and expensive wells, any well intervention operation process is still controlled using traditional surface-read data such as revolutions per minute (RPM), hook load, torque, etc.

The ability to transmit and use downhole intervention process data in addition to surface-acquired data presents significant potential for intervention process optimization, since modern data acquisition technology close to the tool can provide not only more accurate data, but also important additional parameters not available at the surface. Examples of value-adding downhole intervention process data are bore pressure, annular pressure, weight-on-tool, tension-on-tool, torque-on-tool, RPM, workstring bending and dynamic diagnostics. Additional intervention process information on intervention hydraulics or workstring friction can be obtained by feeding existing engineering algorithms with surface- and downhole-acquired data.

This paper discusses the available downhole well intervention process data and demonstrates by a number of case studies the risk reduction value of viewing these parameters in real time. Furthermore, the paper discusses factors constraining the use of the technology and gives an outlook on future developments in well intervention process optimization utilizing real-time downhole data.
Analyzing Underperformance of Tortuous Horizontal Wells: Validation with Field Data
Authors: Kerem M. , Proot M. , Oudeman P.
Published: December 2007

This paper presents the results of a project, which was initiated for analyzing the inflow performance and inflow distribution of one smart and two problematic conventional, long and tortuous horizontal wells in Brunei.

Following a detailed hydraulic analysis of these wells, a good match with the field measurements was obtained. Simulation results show that the problems in the conventional wells were not as severe as those interpreted from the measurements of distributed temperature sensing systems (DTS). It is also demonstrated that the compartmentalized completion with inflow control valves (ICV) in the smart well has added value, as the well would not be producing from the half of the reservoir section without the smart completion.
Reliability Evolution of Permanent Downhole Gauges for Campos Basin Sub Sea Wells: A 10-Year Case Study
Authors: Frota H. M. , Destro W.
Published: December 2007

This work is related to the reliability engineering, specifically, to the analysis of data lifetime and to the failure modeling of Permanent Downhole Gauges (PDG) in 12 oilfields in Campos Basin, Brazil. The area of failure modeling in association with these systems lifetime is the focus of this study.

The importance relies on the application of a methodology as an alternative to reduce the subjectivity in evaluating the reliability and cost / benefit performance of permanent downhole pressure and temperature gauge systems. This methodology also permits the comparison among the components performance from several manufacturers and service companies. Based on these findings, recommendations have been made to achieve reliability improvements from design stage to service operation.
Benchmarking Measurement and Automation Practices in the Upstream Business
Authors: Liddell B. , Deaton D. F. , Mijares G.
Published: December 2007

Whether we call it "digital energy", "digital oilfield of the future", "real time operations", "intelligent fields", "fields of the future" or "E-fields", there is a clear incentive to use technology to maximize asset operational value through increased production and improved efficiencies. The application of visualization, modeling, optimization, and control technologies is a critical component of this effort. This paper describes a study to determine current industry practices and establish a benchmark in the production measurement and automation (PM&A) area. Using a proven analytic methodology, specifically designed to survey and analyze technology utilization, 125 questions were grouped into 17 categories addressing people, process, and technology aspects of PM&A. The presented results are from ten leading independent oil and gas producing organizations.

Interviews were conducted to clarify the participants’ responses; and each response was reviewed and scored using pre-established criteria, consulting experience, and previous assessment results. Participants’ scores were compared to industry averages and the scores of the PM&A leaders using bar and radar charts. Questions included qualitative topics, such as the participants’ automation team organizational model, as well as quantitative questions like the number of engineers per well, and number of historian database points.

This comparison of practices between peer group members participating in the benchmarking process uncovered many significant areas of opportunity for the participants. The results in some categories were as expected and surprising in others. In general, there is a low level of utilization of PM&A, combined with a keen interest in doing more than is currently being done. A few companies exhibited high utilization of automation, with successful results, by leveraging organizations that promote strategic adoption of technology.

This study provides guidance to oil and gas producing companies desiring to increase their productivity through PM&A projects or those desiring to increase their return on PM&A projects. The benchmarking methodology described in this paper is part of a process that uses the results of participants’ current application of technology along with an assessment of the value of opportunities to determine the best path to take toward technology implementation, including strategies and project roadmaps. Studies by independent organizations such as CERA (Cambridge Energy Research Associates) point out quantifiable benefits from the application of digital technology in terms of percent of reserves recovery increase, percent of production increase, and percent reduction in operating costs (1). The presented effort focused specifically on improvements enabled by better measurement, modeling and control technologies. This study also focuses on how the successful implementers of technology are managing the implementation and postimplementation process to assure the capture of the expected benefits.
A New Method for Estimating Average Reservoir Pressure: The Muskat Plot Revisited
Authors: Crump J. G. , Hite R. H.
Published: December 2007

This paper describes a new method for estimating average reservoir pressure from long pressure buildup data based on the classical Muskat plot. Current methods for estimating average reservoir pressure require a priori information about the reservoir and assume homogeneous reservoir properties, or employ empirical extrapolation techniques.

The new method applies to heterogeneous reservoirs and requires no information about reservoir or fluid properties. The idea of the method is to estimate from the pressure derivative the first few eigenvalues of the pressure transient decay modes. These values are characteristic of the reservoir and fluid properties, but not of the pressure history or well location in the reservoir. The smallest eigenvalue is used to extrapolate the long time behavior of the transient to estimate the final reservoir pressure. The second eigenvalue can be used to estimate the quality of the estimate.

Numerical tests of the method show that it estimates average reservoir pressure accurately, even when the reservoir is heterogeneous or when partial flow barriers are present. Examples with real data show that the behavior predicted by the theory is actually observed.

We expect the method to have value in reservoir limits testing, in making consistent estimates of average reservoir pressure from permanent down-hole gauges, and in characterizing complex reservoirs.
Decreasing Well Downtime in Guando Oil Field by Using Continuous Sucker Rod
Authors: Ariza H. , Rojas C. , Rivera V. , Torres F.
Published: December 2007

The Guando oil field, located in Tolima, Colombia, and operated by Petrobras Colombia Ltd., has been developed with S-shape deviated wells, completed with progressing cavity pump (PCP) systems that are driven by centralized conventional sucker rod string.

The increase in sucker rod failures that has accompanied field development has lead to considerable well downtime—a major problem for field growth.

Sucker rod failures are associated with wellbore configuration and production conditions. To resolve the problem, continuous rod string has been implemented in some wells with outstanding success.

This paper describes the influence of wellbore configuration in the performance of conventional sucker rod, comparing the operation of wells with conventional sucker rod with that of wells with continuous sucker rod. Evaluation is based on downtime reduction.

The conclusion is that continuous-rod-string implementation has reduced production loss caused by centralized sucker rod failures in Guando's deviated wells.
Effect of Wettability on High-Velocity Coefficient in Two-Phase Gas/Liquid Flow
Authors: Noh M. , Firoozabadi A.
Published: December 2007

Gas well productivity is affected by two distinct mechanisms: (1) liquid blocking, and (2) high velocity flow in two-phase. The former has been studied extensively recently but the understanding of the latter is limited. High velocity gas flow in single phase has been thoroughly studied by a large number of authors. Despite the fact that high-velocity coefficient in the presence of an immobile and a mobile liquid phase is much higher than that in single phase, only a handful of studies have been carried on the subject. In this work, we have measured the high-velocity coefficient, β in two-phase gas-liquid flow. The results are presented as a function of liquid relative permeability and also liquid saturation. In our measurements, the wetting state is varied by the treatment with a fluorochemical compound. Then the effect of wettability on the high-velocity coefficient in two-phase flow is investigated. Results show that when the liquid is strongly wetting, the high-velocity coefficient increases some 270-fold in water-gas two-phase flow. However, our data show a systematic reduction of high-velocity coefficients for the altered wetting state in two-phase flow. We present measurements of the velocity coefficients in single-phase flow, and in two-phase flow for both oil-gas and water-gas flow for strong liquidwetting and altered-wetting states. Based on our measurements, we conclude that the treatment of the wellbore region can result in significant improvement in well deliverability from the large reduction of high-velocity coefficients.
Effective and Total Porosities: Their Reconciliation in Carbonate and Shaly-Sand Systems
Authors: Mezzatesta A. , Méndez F. , Rodríguez E.
Published: December 2007

Reconciling formation porosity and fluid distribution estimations in carbonate and shaly-sand systems represents a problem that log analysts and petrophysicists face in dealing with well log interpretation. The problem becomes especially challenging when data from conventional (e.g., density, neutron, gamma ray) and non-conventional (e.g., Nuclear Magnetic Resonance (NMR), multi-component induction) instruments are available and need to be combined in a consistent interpretation. Also, the use of effective and/or total porosity petrophysical models may lead to confusion and improper use and interpretation of those quantities.

The paper proposes petrophysical interpretation models for use in the evaluation of carbonate and shaly-sand reservoirs. They allow for effectively and consistently combining the various measurements under the framework of either effective or total porosity. Simultaneous and sequential solutions of the petrophysical models are proposed leading to consistent data integration and reconciliation of porosity and fluid distribution across the various available log measurements.

The proposed interpretation method focuses on the integration of NMR with conventional log measurements in carbonate and shaly-sand environments. With sufficient log data, rocks having complex mineralogy can be interpreted in terms of mineral volumes, irreducible and moveable water saturation, and hydrocarbon saturation. In a shaly-sand environment, results are expressed in terms of sand, shale and fluid saturation distributions.

The paper describes the mathematical formulation of the petrophysical model as well as the applied numerical techniques. Optimal interpretation results are achieved using forward modeling and a constrained, quality-weighted error minimization technique. Field data examples are presented that show the ability of the interpretation models to reconcile porosity, fluid type, and fluid distribution in the pore space.
A Locally Conservative Finite Element Framework for the Simulation of Coupled Flow and Reservoir Geomechanics
Authors: Jha B. , Juanes R.
Published: December 2007

In this paper, we present a computational framework for the simulation of coupled flow and reservoir geomechanics. The physical model is restricted to Biot's theory of single-phase flow and linear poroelasticity,1 but is sufficiently general to be extended to multiphase flow problems and inelastic behavior. The distinctive technical aspects of our approach are:

The space and time discretization of the equations. The unknown variables are the pressure, the fluid velocity, and the rock displacements. We recognize that these variables are of very different nature, and need to be discretized differently. We propose a mixed finite element space discretization, which is stable, convergent, locally mass conservative, and employs a single computational grid. To ensure stability and robustness, we perform an implicit time integration of the fluid flow equations. The strategies for the solution of the coupled system. We compare different solution strategies, including the fully coupled approach, the usual (conditionally stable) iteratively coupled approach, and a less common unconditionally stable sequential scheme.

This computational model has been implemented in an object-oriented reservoir simulator, whose modular design allows for further extensions and enhancements. We show several representative numerical simulations that illustrate the effectiveness of the approach.
Maximizing the Fidelity of Log Signals Transmitted via Digital Telemetry
Authors: Memarzadeh M. , Johnson D. , Gardner W. , Gao L.
Published: December 2007

The efficient and successful recovery of hydrocarbon resources depends heavily on the fast and high fidelity transmission of log (telemetry) signals to the surface. Regardless of the type of telemetry, wireline or wireless, the ultimate quality criterion for communication of log signals is the accuracy to which these signals can be reconstructed at the surface. An optimally designed system should be capable of transmitting as many log signals as possible, with each achieving a minimally acceptable fidelity level. In digital communication theory, the traditional metric for quantifying the transmission fidelity is the bit error rate (BER): the probability of bits being erroneously received at the receiver because of communication channel disturbances. Therefore, the commonly used criterion for designing digital communication systems is based on minimizing the average BER. This approach optimizes the system performance if all bits are equally important and need to be protected equally against transmission errors. Unfortunately, this criterion does not mean that high fidelity signals result.

This paper first presents the mean-squared error (MSE) distortion as a fidelity measure for the end-to-end performance of a digital telemetry system. We then introduce a specific transmission scheme—orthogonal frequency division multiplexing (OFDM)—that enables a simple implementation of a design criterion based on maximizing the end-to-end fidelity. We use the logging-while-drilling (LWD) acoustic telemetry scenario as a case study to demonstrate that, in contrast to optimizing BER, our design not only improves the quality of log signals but also results in significant gains in system throughput. Consequently, many more real-time log signals can be transmitted with acceptable fidelity than other techniques.
Online Water-Injection Optimization and Prevention of Reservoir Damage
Authors: Bringedal B. Ø. , Morud S. A. , Hall N. A. , Huseman G.
Published: December 2007

Waterflood injection on the Shell Bonga field offshore Nigeria is accomplished via a network of subsea flowlines and 15 subsea injection wells. Maximizing water injection volume is an important economic objective for Bonga. Water injection is used for maintaining the reservoir pressure and thereby maximize oil production. The water injection flowrate to each well is limited by the fracture pressure of the overlying shale layer. Fracture of overlying shale could significantly reduce oil recovery from the damaged reservoir.

Hence, it is important to accurately control the reservoir injection pressure such that volume of injected water is maximized without excessive risk of damaging the overlying shales. Since there are no downhole pressure gauges in the injection wells, the downhole injection pressure must be estimated from other measured variables.

For this, we developed a novel technology, WRIPS (Waterflood Reservoir Injection Pressure System). The WRIPS algorithm is used to: ■Estimate downhole injection pressure based on the model and available measurements■Estimate injection pressure uncertainty as a function of available measurements■Calculate an injection pressure target as a function of system conditions■Calculate injection rates for wells where the venturi has failed■Data reconciliation: calculate the most probable pressures and flowrates based on model, measurements, and sensor accuracies■Set conditioned alarm flags

The paper gives a brief description and the experience gained with WRIPS applied to water injection wells. The main contribution from the paper is to demonstrate the benefits with such a system and that the WRIPS is an attractive solution compared to expensive downhole pressure gauges.
Monitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and Carbon Credits
Authors: Benson S. M.
Published: December 2007

Large scale implementation of CO2 Capture and Storage is under serious consideration by governments and industry around the world. The pressing need to find solutions to the CO2 problem has spurred significant research and development in both CO2 capture and storage technologies. Early technical success with the three existing CO2 storage projects and over 30 years experience with CO2-EOR have provided confidence that long term storage is possible in appropriately selected geological storage reservoirs. Monitoring is one of the key enabling technologies for CO2 storage. It is expected to serve a number of purposes – from providing information about safety and environmental concerns, to inventory verification for national accounting of greenhouse gas emissions and carbon credit trading. This paper addresses a number of issues related specifically to monitoring for the purpose of inventory accounting and trading carbon credits. First, what information would be needed for the purpose of inventory verification and carbon trading credits? With what precision and detection levels should this information be provided? Second, what monitoring methods and approaches are available? Third, do the instruments and monitoring approaches available today have sufficient resolution and detection levels to meet these needs? Theoretical calculations and field measurements of CO2 in both the subsurface and atmosphere are used to support the discussions presented here. Finally, outstanding issues and opportunities for improvement are identified.
Integrated Production System Modeling in SPDC, Nigeria
Authors: Vlaardingerbroek R. , Emelle C.
Published: December 2007

As part of the Shell in-house simulation platform, the Hydrocarbon Field Planning Tool (HFPT) provides capabilities for the rigorous integrated subsurface-surface production forecasting in the medium to long term. The flexible programming language and the sophisticated development planning and contracts module have made the tool the core of SPDC's detailed project planning as well as of SPDC's business planning.

Shell aspires to attain zero flaring by end 2008 and so gas commercialization and the subsequent need to plan the size and quality of the various associated and non-associated gas streams; SPDC can no longer simply maximise oil production from its reservoirs, without first performing integrated capacity planning checks. With Associated Gas (AG) being routed to NLNG, there exist a high value optimization opportunity of supply and demand between the SPDC's fields and wells, the capacity of the various oil and gas processing plants (e.g. flow stations, terminals, associated and nonassociated gas plants) and pipelines, and the requirements of SPDC's various gas customers. HFPT addresses problems that cannot be resolved by stand-alone reservoir or surface facilities models and as such brings significant business benefits.

In order to address the above, various models are used in SPDC. The Corporate model describes all 3000+ oil drainage points and is used for annual reserves reporting and for the yearly business planning cycle. The model directly connects to a database.Stranded Assets model describes multi-phase flow from flow-stations without AG facilities to central processing facilities.NLNG supply model granted SPDC a 20-year LNG contract.Western Domestic Gas model (integrated production system with multiple fields that feeds into the prestigious Western Africa Gas Pipeline from Lagos to Benin, Ghana and Togo).Eastern Domestic Gas model (integrated production system feeding into local consumers via various contracts).Forcados-Yokri model, SPDC's largest oil field, were gas lift optimization saved investment in a second lift gas compressor.
A Physically Based Description of Dispersion in Porous Media
Authors: Bijeljic B. , Blunt M. J.
Published: December 2007

We establish a novel methodology to explain the complex macroscopic behavior of dispersion in porous media as a function of Peclet number, Pe, which is ratio of advective to diffusive time-scales at the pore scale. The work combines pore-scale network modeling, continuous time random walk theory and analysis of experiment. We provide a physically-based explanation for the macroscopic behavior of dispersion in porous media as a function of Pe using a pore-network model representing Berea sandstone that accurately predicts the experimental dependence of the longitudinal dispersion coefficient, DL, on Pe. We distinguish all the dispersion regimes, including the diffusive regime, the transition regime at low Pe, as well as the power-law dispersion and the mechanical dispersion regime at high Pe. We can predict the dependence of dispersion on time, Pe and pore structure.

Interpreting transport as a continuous time random walk, we show that: (1) the power-law dispersion regime is controlled by the variation in average velocity between throats (the distribution of local Pe), giving DL ~ Peδ with δ = 3-β ≈ 1.2, where β is an exponent characterizing the distribution of transit times between pores; (2) the cross-over to a linear regime DL ~ Pe for Pe > Pecrit ≈ 400 is due to a transition from a diffusion-controlled late-time cut-off, to transport governed by advective movement; and (3) the transverse dispersion coefficient DT ~ Pe for all Pe >> 1.

We show that the asymptotic dispersion coefficient is only reached after the solute has traveled through a large number of pores, proportional to Pecrit at high Pe. This implies that pre-asymptotic dispersion is the norm, even in experiments in statistically homogeneous media. Furthermore, in natural systems at reservoir scales it is implausible to suggest that a truly asymptotic dispersion coefficient will ever be reached, since larger scales of heterogeneity that enhance dispersion are almost certain to be encountered.
A New Technique To Achieve History Match Using a Probabilistic Approach
Authors: den Boer L. , Poncet J. , Biver P. , Henriquel P. , Marlot V.
Published: December 2007

The main objective of history matching is to improve reservoir representation in order to obtain reliable predictions of production rate and thus optimise future field developments.

Standard history matching techniques are composed of a fixed geological model with global modifications and local adjustments. The limitations with this methodology are clear: local adjustments are not always geologically realistic, static uncertainties are not taken into account and only a limited number of models are used for prediction. In order to solve this problem, a probabilistic approach is presented using uncertainty quantification throughout the history matching process.

This paper describes the process of geological and reservoir uncertainty quantification and ranking, and focuses on specific examples. The result of implementing such a workflow leads to reservoir models which honour the production history of the modelled field.

To achieve a history match, the workflow should consist of the following steps: Probabilistic multi-realizations of the reservoir model taking into account static uncertainty using JACTATM;Calculation of the impact of static uncertainties on the history match by means of reservoir simulation;Calculation of the impact of dynamic uncertainty on the history match using experimental designs;Evaluation of the relative importance of uncertain static and dynamic parameters;‘Hybrid’ geostatistical simulations;Calculation of the impact of the dynamic reservoir parameters on the history match using an experimental design technique;Adjustment of dynamic parameters to obtain a final history match.

This workflow provides the industry with the long-awaited possibility of addressing subsurface uncertainties in a systematic and objective manner. The history matching process shifts from deterministic to probabilistic and results in a more realistic reservoir model which can further be used for true risk assessment prediction.

The workflow proposed increases the chance of attaint the history match. Combining the structural, geological and dynamic uncertainties, covers the whole uncertainty domain, resulting in a multiple history matched reservoir models, which could be used for forecast calculation with more confidence.
Making Sense of the Geomechanical Impact on the Heavy-Oil Extraction Process at Peace River Based on Quantitative Analysis and Modeling
Authors: McGillivray P. R. , Brissenden S. , Bourne S. , Maron K. , Bakker P.
Published: December 2007

The steam injection rates in the CSS operation for the extraction of the Peace River bitumen can be significantly increased by operating at a pressure above the vertical stress of 13 MPa. To improve the understanding of the CSS extraction process, Shell Canada designed and implemented a monitoring program over the most recently drilled production pads. This program included microseismic, surface time-lapse seismic (2D and sparse 3D), a time-lapse 3D VSP, a surface tiltmeter array, and InSAR. Joint interpretation of these data with production data has allowed us to build a conceptual model of the geomechanical response of the reservoir and its effect on the production process.

Dynamic reservoir simulations for Pad 40 were done with the aim to obtain a predictive model. A dilation model from previous simulation work for Cold Lake CSS was applied on the basis of the monitoring analysis and incorporated into the simulations together with a relative-permeability-hysteresis model. A good match of the injection and production volumes, and injection wellhead pressures for the early cycles was achieved using a single well model. Simulation of the later cycles requires a full pad dynamic model constraint by monitoring data, if the heterogeneous steam distribution suggested by the monitoring data becomes significant.