bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir Engineering Aspects of the Captain Extended Well Test Appraisal Program
Authors: Pallant M. , Cohen D. J. , Lach J. R.
Published: December 2007

Texaco UK North Sea is operator and 100% license holder of the Captain Field which contains a greater than 1.5 billion barrel, viscous oil accumulation. Oil production from the Captain reservoir will be dominated by the water / oil mobility ratio of 30, resulting in severe water coning from an aquifer underlying a large section of the field. For this reason the field will be developed with pumped horizontal wells with completion intervals of up to 6000 ft. Key elements which will affect reservoir and well performance are horizontal to vertical permeability ratio, critical water saturation, mobile transition zone height, and horizontal well inflow profile. To evaluate these parameters a 30 day vertical water coning test and a separate 90 day extended production test in a prototype horizontal development well, were performed and the measured water cut performance and bottom hole pressures matched with simulation models. Additionally inflow performance in the horizontal well was assessed by production logs which demonstrated that inflow occurred along the majority of the well length. These two tests were conducted in close proximity to each other in a reasonably homogeneous sand, providing the opportunity for simultaneous and consistent interpretation of the observed data. This integration of the results from two tests of different types has resulted in interpretations which have greater levels of confidence attached to them than would have been possible if the two tests had been performed in isolation.
Reservoir Management in the Ninian Field - A Case History
Authors: Omoregie Z. S. , King G. R. , Strang C. , Hodgson P. , Pressney R. A.
Published: December 2007

The Ninian field is a giant oilfield located in the UK Sector of the North Sea. The field, which had an initial oil in place (STOOIP) of some 2,588 MMSTB, has been on production since 1978. Waterflooding commenced early in the life of the field because, like other Brent Formation fields in the North Sea, Ninian has a highly undersaturated oil and limited aquifer support. In October 1994, the field's cumulative oil production reached the one billion barrel milestone. The projected ultimate oil recovery ranges from 1,120–1,255 MMSTB.

This paper presents the reservoir management philosophy and operating practices at Ninian. It discusses the geology and production history of Ninian. The performance of the waterflood is reviewed. The field development strategy, the effect of reservoir heterogeneity and the steps that are and have been taken to improve areal and vertical sweep efficiency are discussed. The paper then discusses the current and future reservoir management challenges facing a mature oilfield like Ninian and how they will be met A recent re-processing and re-interpretation of the 3D seismic has resulted in new maps for the field and improved definition of the severely eroded and highly faulted East Flank of the field. The paper describes the steps being taken to further develop the East Flank based on the new data.
Effect of Pressure Depletion on Fracture Geometry Evolution and Production Performance
Authors: Mukherjee Hemanta , Poe Bobby , Heidt Harmon , Watson Ty , Barree R. D.
Published: December 2007

A fractured well performance evaluation study, in the Frontier formation of the Moxa Arch area (Southwestern Wyoming), revealed pressure depletion due to older 640 and 320 acre-spaced producers along the NE-S W diagonal in 640 acre sections. This was confirmed by six buildup tests across these sections. Reservoir simulation also showed that the production history of some of these old, 320-acre-spaced wells causes enough pore pressure depletion to affect the fracture geometry in the new 160 acre infill offsets on the other diagonal in the same section. This paper presents the simulated pore pressure distribution in the drainage area of these older wells validated by buildup tests and their effects on the principal effective stress field and consequent fracture geometry evolution around the newer wells.

The present paper also shows that depending on the location of the new well in the depleted zone and the original azimuth of the induced fractures, the newly-created fracture may be asymmetric with only one wing of the fracture extending into the depleted area developing significant length and conductivity. This happens at the cost of development of the other fracture wing. Such asymmetric development of fracture wings can negatively impact production, in addition to the production loss due to actual reservoir pressure depletion.
Formate Brines for Drilling and Completion: State of the Art
Authors: Howard Siv K.
Published: December 2007

Low solids drilling fluids based on formate brines (sodium, potassium and caesium salts of formic acid) were originally designed to minimise frictional pressure losses in slim hole drilling applications. In addition, their unique capability of stabilising polymers to high temperatures made them more temperature resistant than any other polymer based drilling fluids. Subsequent work has shown that these brines, because of their high densities and low corrosivity, are also ideal completion and packer fluids. Formate brines have excellent HSE profiles and they are compatible with reservoir fluids, good shale stabilisers, gas hydrate inhibitors, and scale dissolves. Also, a technique has been found for cost effective clean-up and recycling of formate based drilling fluids.

The commercialisation and introduction of these fluids into the field (especially caesium formate) has taken a long time, due to high prices and few manufacturers. This situation is now changing, as the number of manufacturers is increasing, and buy-back arrangements have been made available. Also, a number of successful drilling and completion trials have been carried out.
Use of Hollow Glass Spheres for Underbalanced Drilling Fluids
Authors: Medley George H. , Maurer William C. , Garkasi Ali Y.
Published: December 2007

Interest in underbalanced drilling is growing worldwide at a rate not seen for a new drilling technology since the introduction of horizontal drilling. Compressible, multi-phase fluids, often present in well bores, make underbalanced drilling difficult. This is a result of the intentional introduction of gas into the fluid either at the surface or through parasite or concentric strings or because of fluid influxes into the wellbore from the formation. Many underbalanced drilling problems would be eliminated by the successful implementation of the incompressible, lightweight drilling fluid described in this paper.
Microseismic Mapping of Hydraulic Fractures Using Multi-Level Wireline Receivers
Authors: Warpinski N. R. , Engler B. P. , Young C. J. , Peterson R. , Branagan P. T. , Fix J. E.
Published: December 2007

Hydraulic fracture diagnostic experiments are being conducted at the GRI/DOE Multi-Site (M-Site) located in the Piceance basin of Colorado. Tests described in this paper use s multi-level advanced-receiver system to bu¡!d on previous work that showed the advantages of using a single advanced receiver to monitor microseisms. The current test has a four-level receiver system monitoring four separate fracture experiments conducted over a one week period, and includes a velocity tomographic survey and detailed orientation survey. Hydraulic fractures were monitored from an offset well 210 ft away from the treatment well The results of these monitoring tests show a fracture developing asymmetrically with time, yielding a fracture-wing asymmetry of 2:1. The fracture initially grows within the pay zone to essentially its total length, and then begins to grow upward, and later in time grow downward. Comparison with fracture models gives only a partial agreement in the final size.
First High-Temperature Applications of Anti-Gas Migration Slag Cement and Settable Oil-Mud Removal Spacers in Deep South Texas Gas Wells
Authors: Sweatman Ronald E. , Nahm James J. , Loeb David A. , Porter Dean S.
Published: December 2007

Applications of a new slag cement and spacer system have reduced the chance of gas channels forming in the cement column during cement hydration in deep, hot south Texas gas wells. These slag cements were formulated with water and conventional cement additives to prevent gas migration and to improve interfacial bonding to oil-wet surfaces. Oil-mud removal spacer fluids (OMRS) were also specially formulated to remove oily residues and improve water-wetting of the oil-wet surfaces. These OMRS can also be designed to develop compressive strength when cementing operations have been completed.

Set slag cement provides a tight gas seal with shear-bond healing capacity, as demonstrated by recently developed HTHP shear-bond strength tests. The previously reported phenomenon of healing or regeneration of slag-mix bonds has been reproduced with slag cement. The rapid development of strength at the top of the long cement column and the improved bonding to oil-wet surfaces were the two major improvements provided by the slag cement. OMRS can clean oil-wet surfaces, and then set once the job has been completed.

Laboratory tests and field evaluations based on cement bond logs and pressure tests indicated improved bonding and isolation of the gas zones. Field applications of slag cements and OMRS fluids have led to greater primary and plug cementing successes in south Texas gas wells, and well production economics have improved accordingly.
An Integrated Sandstone Acidizing Fluid Selection and Simulation to Optimize Treatment Design
Authors: Sumotarto U. , Hill A. D. , Sepehrnoori K.
Published: December 2007

An optimized design of a matrix treatment involves fluid selection and acidizing simulations to predict the outcome of the treatment; Many matrix acidizing treatment designs and fluid selections have been successfully accomplished by utilizing expert system technology. However, none of these present a complete and optimized result (i.e., by utilizing the output of the expert system to predict the acidizing outcome using an acidizing numerical simulator). In the meantime, several acidizing computer simulation studies have been conducted separately. This paper presents a study which integrates the treatment design, particularly the fluid selection process, and acidizing simulation for sandstone formations. Required parameters for sandstone acidizing such as acid type, concentration, volume, and injection rate/pressure are first selected using an expert system. The output from the expert system is further used for the input to an acidizing numerical simulator (UTACID). A new sandstone acidizing reaction model, appropriate for a high-temperature environment, and anisotropic medium have been implemented into UTACID to enhance the performance of the simulator. The expert system and the simulator have been integrated to provide an optimization tool for sandstone acidizing treatment design and simulation.
Approach to Casing Design for Service in Compacting Reservoirs
Authors: Cernocky E. P. , Scholibo F. C.
Published: December 2007

Depletion of unconsolidated sand reservoirs can cause compaction of the reservoir sand. This strain transfers load to the casing, and this can kink and crush the casing, preventing workovers and requiring redrilling wells (Figure 1). Early redrilling can have significant negative impact on project earning power, so it is necessary to design casing to withstand compaction loading. This paper explains Shell Oil's new compaction design philosophy for casing to be run in some highly compactive Gulf of Mexico reservoirs. The paper explains the technical tools used to quantify compaction loading; the relative importance of different casing damage mechanisms; and Shell's approach to designing casing to mitigate the influence Of compaction.

Shell's approach to compaction emphasizes minimizing column buckling under axial compaction loads and collapse under transverse compaction loads. The approach to buckling is based on a model that quantifies the ability to work through buckled casing, The approach to collapse is based on a model linking depletion to the load transferred between the sand, cement, and casing. The compaction solution is specialized to Gulf of Mexico sand and reservoir characteristics.

Casing design is only one aspect of the multidisciplinary solution to the compaction problem. Compaction-tolerant sand control must be included in the completion design, and advanced core testing must be used to link the casing design to the stress-strain behavior of unconsolidated sands. Where historical damage exists, downhole casing logging has been used to guide and validate the solution. These other facets of compaction technology go beyond the scope of this paper but have been addressed by Shell Oil's integrated approach to the compaction problem.
Mud Clean-Up in Horizontal Wells: A Major Joint Industry Study
Authors: Ryan D. F. , Browne S. V. , Burnham M. P.
Published: December 2007

This paper describes a major joint industry study into the effectiveness of mud clean-up techniques for horizontal wells involving eight oil and service companies. Experimental work was carried out on a small scale laboratory clean-up rig to quantify mud damage and test breaker effectiveness. Large scale flow loop testing was used to evaluate overall ciean-up techniques including displacement efficiency and damage to pre-packed screen completions.

Tests on a wide variety of mud systems showed surprisingly little difference in the performance, from a formation damage perspective, on clean sandstone cores. Oil based muds were, however, found to produce less damage than water based muds. A range of breakers were tested with each mud system. There was a large variation in the results of breaker testing, with breakers, unexpectedly, sometimes causing an increase in the pressure required to break through mud filter cake and/or formation damage. Whole mud was found to cause significant damage to pre-packed screens; this damage was sometimes, though not always, removed during clean-up. Poorly centralised screens were found to result in large amounts of mud and debris on the low side of the hole.
General Heterogeneous Radial and Linear Models for Well Test Analysis
Authors: Levitan M. M. , Crawford G. E.
Published: December 2007

This paper presents a new analytical method for an exact solu-tion of the presure transient problems for general radial and linear models with heterogeneities. In these models, the stora-tivity and the transmissivity coefficients are considered functions of the distance from the well.

The solution method is based on special transformation of variables which reduces the problem to a diffusivity equation with constant coefficients. This equation is then solved in the Laplace transform domain and the solution is inverted into the real time domain by the Stehfest algorithm. The solution method allows both continuous variation as well as discontinuities of the rock and fluid properties.

The new solution algorithm reproduces exactly all known exact solutions for specific variation of properties including the multicomposite radial and linear model solutions.
Processing of Data From an NMR Logging Tool
Authors: Freedman R. , Morriss C. E.
Published: December 2007

A new pulsed nuclear magnetic resonance (NMR) logging tool, known as the CMR* Combinable Magnetic Resonance tool, is being used worldwide. During the CMR tool development phase, one challenge was to design a robust and economical data acquisition and signal processing scheme for the hundreds or thousands of spin-echo amplitudes that can be acquired during the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence. This challenge was met by developing a new signal processing and associated downhole data compression algorithm. Data compression is essential to reducing the processing times so that formation T2-distributions can be estimated in real time. Compression of the digital data is possible, without loss of information, because the linear dependency of the NMR measurement kernels results in gross redundancy of the measured spin-echo amplitudes.

An attractive feature of the algorithm described in this paper is that the compression can be performed in the downhole tool, thus substantially reducing the telemetry requirements. The raw spin echoes can also be sent uphole and made available for additional processing.

Logs of CMR porosity, free-fluid porosity, mean relaxation time and rock permeability are computed from the estimated T2-distributions. The accuracy and precision of the CMR log outputs are demonstrated by repetitive Monte Carlo computer simulations in which noisy, synthetic spin-echo amplitudes are generated from known T2-distributions and then processed to obtain log outputs. Monte Carlo simulations are used to elucidate CMR log responses in typical clean sand, shaly sand, and carbonate rocks. The relative insensitivity of the measurements to short relaxation times (e.g., those less than a few milliseconds) is discussed and used to explain the differences between CMR log porosity and "total" formation porosity in shaly formations. We show that CMR porosity is an "effective porosity" that does not include clay bound water and microporosity having relaxation times less than a few milliseconds.

We give examples of statistical fluctuations that can occur on estimated T2-distributions to assist log analysts in recognizing artifacts that are not indicative of actual reservoir rock properties. Field logs that display many of the features of CMR log responses revealed by the simulations are also presented.
Reservoir Characterization by Integrating Well Data and Seismic Attributes
Authors: Yang An-Ping , Gao Yaming , Henry Steve
Published: December 2007

Fueled by the continuing development of computer technology, traditional techniques for reservoir characterization have evolved into a multi-disciplinary process. In particular, geostatistical techniques have provided a framework for integrating all available engineering and geoscience data. In this paper, we will demonstrate a seismic-guided geostatistical method on a realistic seismic data set. A cross section from a three-dimensional reservoir facies model was used to test the capabilities of this method. Synthetic seismic data were generated from the geologic cross section and then input to a seismic inversion process to estimate acoustic impedance. Five porosity logs derived from the known model were used as hand data. Using this hard data, and utilizing varying correlation coefficients between the hard data and soft data, a set of gridded maps were generated using a geostatistical method.

Comparisons of the results with the known model clearly indicate the potential of this type of approach to provide meaningful reservoir characterizations consistent with the available data. The integration procedure illustrated in this paper can be used as a basis by engineers and geoscientists to develop specific procedures for their applications. The demonstrations in characterization quality improvement can be used to justify the need for integrating seismic data into the reservoir description process.
Integrated Geostatistical Reservoir Description Using Petrophysical, Geological, and Seismic Data for Yacheng 13-1 Gas Field
Authors: Yang C. T. , Chopra A. K. , Chu J. , Huang X. , Kelkar M. G.
Published: December 2007

Seismic data are routinely and effectively used to delineate the structure of a reservoir. However, the use of seismic data in reservoir modeling has been limited. This paper introduces a new approach of incorporating 3-D seismic data in reservoir porosity modeling. This approach employs a stochastic seismic inversion technique to generate the seismic impedance. The inversion technique uses a modified stochastic hillclimbing method. Correlation between porosity and the inverted impedance is established at well locations. The resulting relationship is used to generate 3-D porosity models. The generation of these models involves a stochastic co-simulation of inverted seismic impedance of loc-derived porosity.

This modeling technique is applied to the Yacheng 13-1 Gas Field. The results are compared with porosity models generated using well-log data only, as well as with using seismic amplitude and well-log data since a good correlation between seismic amplitude and well log data is also observed after transforming the data into similar scales.

The results demonstrate a protocol for early integration of geological and geophysical data in a gas reservoir. This approach will allow easy revision and refinement of the description with additional data, such as new well data or new interpretation of the existing data.
Optimizing Horizontal Well Locations Using 3-D, Scaled-Up Geostatistical Reservoir Models
Authors: Goggin David. J. , Gidman June , Ross Steve E.
Published: December 2007

This paper demonstrates how horizontal well locations may be optimized by maximizing recovery and minimizing the number of wells. The study is unique in that we had a large number of wells penetrating a reservoir interval which had been developed by only two horizontal wells. We combined structural and stratigraphic information with processed log data available from 67 vertical wells drilled for a deeper reservoir target. 3-D, 161 cell layer geostatistical models of porosity, permeability, and inital water saturation were built from the log data. Variations in porosity and initial water saturation were kriged, while permeability heterogeneity was captured through conditional simulation.

Scaled-up, 42 cell layer versions of the geostatistical models were built for full-field simulation. The 3D scale up process preserves effective permeability and connectivity of the main flow units in the full-field model. Proportional volumetric averages of porosity and saturation were also preserved.

Two existing horizontal wells were history-matched on the scaled-up model. Thirty-year production forecasts for more than twenty proposed horizontal well locations were tested. Proposed well locations were tested individually, in pairs, and in triple combinations. Well locations were designed to tap high permeability flow units, and maximize the distance to the oil-water contact. Results from paired well combinations show the impact of well-to-well production interference on incremental oil recovery. Using these results, we were able to maximize incremental recovery for a minimum number of proposed horizontal well locations.
Fractured Reservoir Characterization and Performance Forecasting Using Geomechanics and Artificial Intelligence
Authors: Ouenes A. , Richardson S. , Weiss W. W.
Published: December 2007

A new approach in fractured reservoir characterization and simulation that integrates geomechanics, geology, and reservoir engineering is proposed and illustrated with actual oil reservoirs. This approach uses a neural network to find the relationship between, reservoir structure, bed thickness and the well performance used as an indicator of fracture intensity. Once the relation established, the neural network can be used to forecast primary production, or for mapping the reservoir fracture intensity. The resulting fracture intensity distribution can be used to represent the subsurface fracture network. Using the fracture intensity map and fracture network, directional fracture permeabilities and fracture pore volume can be estimated via a history matching process where only two parameters are adjusted.
Characterization and Simulation of Naturally Fractured Tight Gas Sandstone Reservoirs
Authors: Harstad Hugo , Teufel Lawrence W. , Lorenz John C.
Published: December 2007

Significant gas reserves are present in low-permeability sandstones of the Frontier Formation in the Green River Basin, Wyoming. Successful exploitation of these reservoirs requires an understanding of the characteristics and fluid-flow response of the regional natural fracture system that controls reservoir productivity. Fracture characteristics were obtained from outcrop studies of Frontier sandstone at five locations in the basin. Fracture characterization involved construction of detailed fracture network maps of outcrops that provided information on the fracture orientations, lengths, and spatial distribution. The fracture network maps clearly demonstrate that regional fractures are a unidirectional set of fractures that are perpendicular to bedding and have varying length and spacing. The spatial distribution of regional fractures is controlled by bed thickness, with fewer and longer fractures per unit area as bed thickness increases. The fracture data was combined with matrix permeability data to compute an anisotropic horizontal permeability tensor (magnitude and direction) corresponding to an equivalent reservoir system in the subsurface. This analysis shows that the maximum and minimum horizontal permeability is controlled by fracture intensity and decreases with increasing bed thickness. The relationship between bed thickness and the calculated fluid-flow properties was used in a reservoir simulation to predict gas production from vertical, hydraulically-fractured wells and horizontal wells of different lengths in analogous naturally fractured gas reservoirs. Simulation results show that horizontal wells drilled perpendicular to the maximum permeability direction can maintain a high target production rate over a longer time and have higher cumulative production than vertical wells. Longer horizontal wells are required for the same cumulative production with decreasing bed thickness.
Practical Considerations in the Analysis of Gas-Condensate Well Tests
Authors: Raghavan Rajagopal , Chu Wei-Chun , Jones Jack R.
Published: December 2007

Several pressure buildup tests are analyzed with a view to evaluate the potential of the ideas given in the literature. A broad range of tests is examined to demonstrate the characteristics of responses in wells producing below the dew point. Methods to obtain quantitative information that is consistent for different tests are outlined.
Invasion-Based Method For Estimating Permeability From Logs
Authors: Semmelbeck M. E. , Dewan J. T. , Holditch S. A.
Published: December 2007

We have developed a new method of estimating permeability from logs. Our method, called PermLog, is mechanistic rather than empirical and does not require extensive (and expensive) core analysis for calibration. PermLog is based on modeling filtrate invasion from the time a zone is penetrated until it is logged. This method provides reasonably good estimates of permeability in moderate permeability formations. Similar methods applied to time-lapse logging have been presented by Tobola and Holditch1 and Yao and Holditch.2 Our method has been improved over these earlier works in two significant ways. First, our method is applied to the prediction of new generation array induction logs and docs not require multiple "time-lapse" logging runs. The development here is applied to the Schlumberger AIT log but our method is extensible to any tool which can provide a resistivity profile of the reservoir surrounding the wellbore. Second, our model includes an experimentally-verified model for predicting mudcake thickness and permeability during static and dynamic filtration conditions.3,4

PermLog is an important step in tying the static or volumetric petrophysical data normally associated with log analysis to the fluid flow petrophysical information required for reservoir performance prediction. Reservoir engineers, petrophysicists, geologists and geophysicists are challenged to bring their specialties to bear on the problem of creating a reservoir model which can be used to optimize the value of oil and gas reservoirs. Layered and otherwise complex models arc more often applied to interpret well tests and production data to reflect our increased understanding of the importance realistic models have in predicting and optimizing reservoir performance.5,6 Acquiring sufficient data to satisfy these analysis methods is often too time consuming and expensive. PermLog, in conjunction with new generation logging tools, provides a much-needed source of information on the distribution of permeability within reservoirs.

This paper presents a description of the PermLog model, the underlying assumptions and the data requirements necessary to apply this technology. We also present comparisons between PermLog estimates and core measurements of permeability. The permeability estimates agree quite well with core data and the trends of permeability within an interval match up very well with the trends from cores.
Through Casing Resistivity Measurements and their Interpretation for Hydrocarbon Saturations
Authors: Vail W. B. , Momii S. T. , Dewan J. T.
Published: December 2007

Through casing resistivity logs obtained at three different wells are reviewed including the logs from a blind test. The physics necessary to interpret the data is presented in brief form and future corrections to data are discussed. Anticipated applications for the technology are described.
A Multiarray Induction Tool Optimized for Efficient Wellsite Operation
Authors: Barber T. , Orban A. , Hazen G. , Long T. , Schlein R. , Alderman S. , Tabanou J. , Seydoux J.
Published: December 2007

A new multiarray induction tool has been developed as part of the Platform Express,* a suite of tools intended to significantly improve wellsite efficiency. The tool measures formation conductivity with eight arrays ranging in length from 6 in. to 6 ft. Previously published methods1 are used to provide logs with 90% vertical resolutions of 1, 2 and 4 ft, each with depths of investigations of 10, 20, 30, 60 and 90 in. Integral to the tool is a sensor that measures the mud resistivity to provide accurate borehole corrections for the induction logs. The total length of the instrument package is 16 ft.

One problem encountered in multiarray induction tools is stick-slip motion of the tool in the borehole. To solve this problem an accelerometer included in the high-efficiency toolstring is used to provide real-time depth correction for nonuniform tool motion for all the tools in the string. In addition, this guarantees that the high-resolution logs are on depth with each other.

A special effort has been made to extend multiarray induction technology into more difficult logging conditions. A new algorithm that provides improved logs in very rugose boreholes and salty conductive mud has been developed and applied to the log processing of this tool. Additional features include correction to the resistivity logs for dip or deviation up to 60 degrees and more accurate estimates of Rt in the presence of annulus. The effectiveness of these algorithms has been demonstrated in case studies with both computed and field logs.
Shear Sonic Interpretation in Gas-Bearing Sands
Authors: Brie A. , Pampuri F. , Marsala A. F. , Meazza O.
Published: December 2007

The introduction, a few years ago, of shear dipole sonic logs gave the industry the possibility to record high-quality shear and compressional slownesses in soft formations. Data sets were acquired and analyzed on Vp/Vs versus Δtc crossplots. Trends were identified in sands and shales and were matched with semi-empirical correlations based on the Gassmann formalism. These trends can be used to quality control shear logs and for quicklook lithology interpretation.

The presence of gas in soft formations makes the interpretation more complicated as it can affect the sonic slownesses significantly, in particular the compressional. On the Vp/Vs crossplot, gas-bearing formations clearly differentiate from liquid filled formations. However, quantitative interpretation of the gas effect with the Gassmann equation gives deceptive results, although this model is successfully used in geophysics interpretation at a lower frequency. We indicate that the Gassmann model itself is not at fault. The responsibility is with the pore fluids mixture law used to compute the average fluid properties. We therefore propose a new empirical mixture law that better fits laboratory measurements and field observations. Using this revised model realistic gas trends can be identified on the Vp/Vs crossplot. The model can be solved to evaluate gas volume from compressional and shear slownesses. Additionally, the effect of shaliness can be accounted for. The results agree well, in most instances, with flushed-zone saturation obtained from resistivity measurements and provide another opinion on gas volume. An additional product of the interpretation is to provide reliable values of dry-frame dynamic elastic constants of the rock for possible subsequent use in a rock mechanics evaluation.
Ultrasonic Rate Measurements in Two-Phase Bubble Flow
Authors: Kumar Manoj , Home Roland N.
Published: December 2007

One of the most important tools in well testing and production logging is the downhole flowmeter. Unfortunately, existing spinner and tracer tools have limited accuracy in low-rate single phase flow and multiphase flow situations. Two experimental studies investigated the use of ultrasonic methods to measure flow rates under these conditions. The experiments showed that the ultrasonic transmission method can be used for accurate measurements of low-rate single phase water flow. The ultrasonic reflection method provided reasonably accurate bubble velocities in two-phase bubble flow regime under laminar flow conditions.

Experiments using ultrasonic transmission provided higher accuracy and better sensitivity in measurement of low-rate single phase water flow than conventional methods. The one-inch square flowcell device investigated in this study used the trans-mission properties of ultrasonic waves to measure the volumet-ric rate in single phase water flow. The flow cell was installed in a vertical flow loop. Water also passed through a section where the weight of water was recorded accurately against time, thus giving another rate measurement for cross-checking purposes. The device-measured flow rates were compared with actual rates obtained by the weight measurement. The device was accurate down to a flow rate of 1.0 gallon/min, which is the slowest flow rate achievable in this loop. Such a low flow rate would normally be difficult ta measure using a conventional spinner tool.

Experiments using ultrasonic reflection examined how accurately an experimental flow tool measured bubble velocity in a two-phase bubble flow regime. Measurements were made in a graduated, transparent pipe with an inside diameter of 5.50 inches. The tool diameter is 3.25 inches. Gas and oil were bubbled through a stagnant column of water, and bubble velocities were measured. To cross-check the accuracy of tool measurements, bubble motion was also recorded using a video camera. The video frame had a clock, with a resolution of one hundredth of a second, providing time information. Tool-measured bubble velocities were compared with actual velocities determined by a frame-by-frame playback of video data. The tool readings were linearly related to the actual velocities in the range from 0.38 ft/sec to 1.30 ft/sec, although the velocities registered by the tool were consistently in error. This velocity information, in combination with the void fraction data, will provide the dispersed phase volumetric flow rate. The result is significant because, in contrast to the currently employed spinner and tracer tools, this technique can provide us with flow rates for individual phases in a two-phase bubble flow situation.
Hydrate Plug Decomposition: Measurements and Modeling
Authors: Yousif M. H. , Dunayevsky V. A.
Published: December 2007

Depressurization (venting) is almost the only option available to remove hydrate blockages from subsea natural gas or gas condensate pipelines. This process is normally applied with little or no accurate information about the plug location, size or composition.

Hydrate decomposition by depressurization is a heat and mass transfer dependent process. Quantifying this dependency is necessary to perform an optimum plug removal scheme.

In this paper, a moving boundary mathematical model is developed to predict the decomposition rate of a hydrate plug under various depressurization scenarios. The model was validated experimentally by measuring the rate of decomposition of hydrate plugs in a 2 inch internal diameter, 38.5 inch long pipe. The motion of the hydrate plug/gas interface is tracked by 16 pairs of infrared light transmitters and receivers diametrically positioned across the pipe.
Improved Completion Designs In The Hugoton Field Utilizing Multiple Gamma Emitting Tracers
Authors: Hecker M. T. , Houston M. E. , Dumas J. D.
Published: December 2007

Multiple gamma emitting tracers and post fracture spectral gamma ray logs were used to optimize production and improve the completion designs of 150 gas wells in the southwest Kansas region of the Hugoton Field. The information from the tracers and logs has revealed unstimulated pay zones and has been the impetus for completion modifications, yielding substantial gains in production. Through the use of limited stress barriers and permeability variations, perforation schemes have been successfully modified to improve fracture containment and proppant placement over the 200 ft Chase Group intervals. Previously these intervals were treated with multiple individual zone treatments.
Sequential Decision Analysis and Risk Analysis for Antarctic Offshore Petroleum Development
Authors: Belke D.
Published: December 2007

Integration of geological, engineering, environmental and economic parameters of the Ross Sea, Antarctica led to the development of a quantitative assessment of potential petroleum development in this region. A decision analysis model of 90 outcomes (excluding ‘no’ decisions) indicated that the best alternative is a 400,000 Bopd production scenario. This is based on reduction of capital investment of US$7.6 billion (base case) by US$2.2 billion and producing an equal volume as in the base case (400,000 Bopd). A risk analysis model, based on cumulative probabilities, indicated that a US$ 15 increase in the price of oil has more impact on Antarctic petroleum development than a combined 75% decline in capital and operating costs.
A New Generation of Gas Hydrate Inhibitors
Authors: Kelland M. A. , Svartaas T. M. , Dybvik L.
Published: December 2007

New, cost-effective, and environmentally acceptable hydrate inhibitors that allow multiphase fluids to be transported untreated over long distances have been under increasing investigation by the oil and gas industry.

Replacing traditional hydrate inhibitors such as methanol and glycols with a new generation of hydrate inhibitors can lead to very substantial cost savings, not only for the reduced cost of the new inhibitor but also in the transportation costs and the size of the injection, pumping and storage facilities. Thus it is possible to redesign production facilities on a smaller scale. Such a change-over in hydrate inhibitor technology may also be an environmental requirement in the near future.

We will present an overview of patent and other literature on new hydrate inhibitors, including specific chemicals that have been investigated. Our own results on some of these published chemicals will be given and their applicability compared. We will also present data on new inhibitors developed at RF, as well as improved methods of evaluating their activity. A discussion of the relative merits of the two main types of new hydrate inhibitor, "kinetic inhibitors" and "anti-agglomerators", will be given.
New Dual Completion Method Eliminates Bottom Water Coning
Authors: Swisher M. D. , Wojtanowicz A. K.
Published: December 2007

This paper discusses the design, implementation, and results of a new completion method to eliminate bottom water coning. This method uses a dual completion in the same zone to produce water-free oil at higher rates than conventional completions. This is accomplished by producing water from perforations below the oil-water contact, at the same time that oil is being produced from perforations at the top of the sand. The method is currently being used in the Nebo Hemphill Field in North Louisiana. Mathematical models are used to assist in the design of this completion. With this modeling, the perforation spacing is determined, along with an estimate of the water production needed to prevent coning. The first well to use this new completion method has been on production for over a year. This paper documents the production rates, and economic success of the test well using this completion method.
Oil Spill Detector for Un-Manned Platforms
Authors: Dalland K. I. , Jouve P.
Published: December 2007

Efficient operation of un-manned oil platforms has given increased demand for new instrumentation. Simrad has together with Elf Petroleum Norge developed a Marine Oil Spill Detector, an autonomous system for detecting oil slicks in the vicinity of the platform. The system should based on the movement of the slick locate its source, and primarily give alarm if the oil comes from the platform itself or any of its subsea installations.

The Oil Spill Detector consist of a standard marine radar antenna interfaced to and controlled by a PC based processing station. It monitors the vicinity of an oil platform to detect the reduction in sea clutter caused by the damping effect of oil on surface waves.

This paper describe two demonstration tests of the system. The system was during the first test located on the roof of our office building close to the waterside in the Bergen harbor where slicks formed by only 5 liters of oil was tracked for more than 20 minutes. The second test was an offshore test conducted by NOFO ( Norwegian Clean Seas Association for Operating companies ) where up to 100 m3 crude oil where spilled and recovered.
Simulation of Well Productivity Losses Due to Near Well Condensate Accumulation in Field Scale Simulations
Authors: Malachowski M. A. , Yanosik J. L. , Saldana M. A. , Batten A. H.
Published: December 2007

Accurate simulation of well productivity losses due to condensate buildup generally requires a finely gridded radial model and either a fully implicit or adaptive implicit solution method. Computer costs for including the grid refinement necessary to capture near well liquid dropout effects in full field, compositional simulations can be extreme even for models with local grid refinement and adaptive implicit capabilities. We propose an alternative simulation method which accurately computes condensate blockage effects in multiwell, full field simulations without local grid refinement. The method is based on the use of correlations of "pseudo skins" which can then be combined with a general well function equation to capture the effects of well productivity losses. The correlations are developed prior to running a full field model by running a series of fine radial grid and coarse Cartesian grid single well simulations to define the relationship between the true wellbore pressure (obtained from the fine grid simulation) and the well block pressure in the coarse grid.
Optimizing Recovery From A Strong Water-Drive West Texas Gas Reservoir Through Integrated Reservoir Simulation Studies
Authors: Hulme J. R. , Colleary W. M. , Van Kirk C. W.
Published: December 2007

This paper presents a field study funded by the Gas Research Institute (GRI) to determine reservoir management and production strategies to economically maximize recovery from the Vermejo/Moore-Hooper strong water-drive gas reservoir in West Texas. The reservoir is greater than 16,000’ deep and contains high pressure sour gas, and it is composed of geologically complex fractured dolomite and chert. The water drive is exceptionally strong, the reservoir has experienced no more than 5 percent pressure depletion during its 20-year history, and late in life the field is beginning to re-pressurize. Detailed Engineering and Geologic studies were performed and reservoir simulation of the field tested the most effective methods to economically maximize recovery.

The management strategies evaluated were comprised of various methods to maximize field productivity, reduce bottom-hole flowing pressure, improve the ability of the wellbore to unload water and reduce/retard aquifer influx. Specific strategies that were tested included the drilling of an infill well, placing the wells on compression, installation of coiled tubing, installation of gas lift, installation of an optimal tubing string, injection of a permeability barrier into the reservoir and de-pressuring the aquifer by downdip water production.

It was concluded that the most economic method to deplete the field was to place the remaining wells on compression at 200 psia wellhead pressure and to install coiled tubing when the wells begin to experience water load-up problems. The gas-lift and optimal tubing cases predicted higher recoveries, but were economically less favorable. The methods tested to reduce aquifer influx to the reservoir actually decreased recovery of gas reserves. The study also identified the need for a multiphase flow correlation which fully handles the complexity involved with high water-gas-ratio systems (up to 10 stb/mscf).
A NEW GENERATION SOLUTION ADAPTIVE RESERVOIR SIMULATOR
Authors: Deb Manas K. , Reddy Mahender P. , Thuren John B. , Adams Wilton T.
Published: December 2007

This paper describes a new general purpose three – dimensional multi-phase reservoir simulator that uses fully unstructured curvilinear meshes and employs dynamic mesh adaptivity based on a flow solution. The simulator is based on an unconventional finite element framework called hp finite elements (where h refers to the local mesh size and p refers to the order of the local polynomial approximation). The simulator is coded as an application layer on top of a general-purpose solution-adaptive hp-finite element kernel. This kernel incorporates advanced object-based data structures that allow simultaneous manipulation of h (via refinement/unrefinement) as well as p (via enrichment/ unenrichment).

The simulator supports both IMPES as well as fully implicit schemes. It offers an automatic time stepping strategy. The numerical difficulties associated with advec-tion terms and presence of solution near-discontinuities are overcome using SUPG (Stream-wise Upwind Petrov Galerkin) method with a discontinuity capturing (DC) operator. The simulator achieves higher computational efficiency by anisotropic hp-type mesh adaptation. It does not use a predetermined well model (such as Peace-man’s well model). Instead the wells are represented exactly and modeled right up to (and sometimes including) the well bore. The simulator is equipped with both direct and iterative solvers. The iterative solvers are also parallelized. Several validation and demonstration cases solved using this simulator are presented in the paper. It is anticipated that this simulator will provide unprecedented computational advantages when handling geologically complex reservoirs with non-trivial and non-traditional well shapes and perforations.
Reservoir Management and Optimization of the Mitsue Gilwood Sand Unit #1 Horizontal Hydrocarbon Miscible Flood
Authors: Winter B. T. , Edwards K. A.
Published: December 2007

The performance of a two-stage hydrocarbon miscible flood project at the Mitsue field, Alberta, Canada is updated. The reservoir management issues pertaining to the miscible flood project are also discussed, particularly the use of a relational database to store and manipulate the large quantities of data associated with the miscible flood project. Lastly, the chase gas optimization efforts undertaken since original project design are discussed. The Hybrid finite-difference/streamtube technique has been used to modify the chase gas injection slug size and WAG ratio.