bluuebunny/crossref_metadata_2025 huggingface dataset:
General Productivity Models for Wells in Homogeneous and Layered Reservoirs
Authors: Larsen Leif
Published: December 2007

The need for simple models to estimate the productivity of arbitrary wells in homogeneous and layered reservoirs should be obvious. The current paper addresses this problem by extending current analytic methods to handle a greater variety of well configurations. One of the more important extensions covers deviated wells with limited flow entry through a fairly simple summation scheme. Another being the treatment of wells with a limited height fracture.

Two basic drainage shapes are included in the models: Circular and other regular drainage shapes with the well clearly inside the drainage area, and rectangular without any restriction on well length and location for homogeneous and commingled layered reservoirs, but with the well required to lie clerly inside the drainage area for crossflow systems. For highly deviated wells the rectangular models are based on the approach of Goode and Kuchuk1 for horizontal wells, with the difference between the deviated well and a horizontal well handled through a modified skin value. Fractures of limited height are also based on Ref. 1 by adding an appropriate skin value.
Handling Production-Data Uncertainty in History Matching: The Meren Reservoir Case Study
Authors: Kabir C. S. , Young N. J.
Published: December 2007

History matching reservoir performance ordinarily implies adjusting geologic and rock-fluid flow properties until a satisfactory match is attained between the observed and model response. Property adjustments inevitably imply a trial-anderror approach.

Regardless of the approach used in any study, we presuppose the integrity of observed data. Unfortunately, measurements of gas and water do not have the desired precision when oil is the primary fluid of interest. For instance, when gas is flared, the quality of metering suffers. In some operations, withdrawal of small samples of a three-phase mixture near the wellhead becomes the sole basis for establishing water content in a production stream. These practices often introduce large uncertainty in reported data of all three phases.

This paper explores how we dealt with some of these issues while attempting to match 30-year performance in the Meren field in offshore Nigeria. Results show that production data, affected by wellbore mechanical problems, can be diagnosed using log-log type curve. Furthermore, this work shows that discerning watercut from wellhead samples is prone to errors, and issues with wellbore flow calibration can lead to large uncertainties in performance prediction.
Assessment of Uncertainty Assessment Methods
Authors: Liu Ning , Betancourt S. , Oliver D. S.
Published: December 2007

Uncertainty in future reservoir performance is usually evaluated from the simulated performance of a small number of reservoir models. Unfortunately, most of the methods for generating reservoir models conditional to production data are known to create a distribution of realizations that is only approximately correct. The adequacy of the approximations is unknown, although several previous investigations of the approximate algorithms have suggested that the distributions of realizations could be badly misleading. In this paper, we evaluate the ability of the various sampling methods to correctly assess the uncertainty in reservoir predictions by comparing the distribution of realizations with a standard distribution from a Markov chain Monte Carlo method.

This study compares the ensemble of realizations from five sampling algorithms for a synthetic, one-dimensional, single-phase flow problem, in order to establish the best algorithm under controlled conditions. The small test problem was chosen in order that a large enough number of realizations could be generated from each method to ensure the statistical validity of the comparisons. Five thousand realizations were generated from each of the approximate sampling algorithms. The approximate sampling methods evaluated were linearization about the maximum a posteriori model (the square-root of the covariance matrix method), randomized maximum likelihood, and two two pilot point methods with six and nine pilot points locations. Realizations were also generated by a Markov chain Monte Carlo method with local perturbations and an attempt was made to generate realizations from a rejection sampling algorithm. The distributions of realizations from the approximate methods were compared to the distributions from the exact, methods. While the approximate sampling methods performed relatively well for evaluating uncertainty in average reservoir porosity and effective steady-state permeability, most failed to adequately assess uncertainty in some other function of the reservoir model such as the distribution of extreme permeability values or the data mismatch. In general, the method of randomized maximum likelihood performed better than other approximate methods.
History Matching Using a Streamline-Based Approach and Exact Sensitivity Coefficients
Authors: Gautier Y. , Noetinger B. , Roggero F.
Published: December 2007

Geostatistical models provide detailed geostatistical images of the reservoir containing several millions of gridblocks. Reservoir engineers often have to deal with history matching problems: they have to find images that honor production data. This is often time consuming due to the large number of numerical simulations that often have to be run.

Optimization coupled with gradient-based methods enables to efficiently find a reservoir representation that respects all static and dynamic data. Nevertheless, for multiphase flow or for compositional problems, only relatively small models can be handled with a finite volume flow simulator.

Streamline-based simulation provides accurate and fast estimates to various flow problems. Simulations can also be performed on large fine grid geological model. Recently, streamline-based simulation has been used for inversion problems. Analytical gradients of production data with respect to a geostatistical parametrization have been computed for the tracer flow case. This approach can not take into account changes in boundary conditions or multiphase flow. In this paper, we will derive the gradients for two-phase flow problems without any assumption concerning the boundary conditions. The gradients will then be used in an optimization loop for a synthetic history matching problem.
Applied Multisource Pressure Data Integration for Dynamic Reservoir Characterization, Reservoir, and Production Management: A Case History from the Siri Field, Offshore Denmark
Authors: Borch Carsten
Published: December 2007

The Siri Field offshore Denmark is a small Paleocene sandstone reservoir. The field has a low structural relief and a thin undersaturated oil column with a bottom aquifer. The formation consists of firm, fine to very fine-grained, cross-bedded to massive sandstone with abundant glauconite reflecting deposition by deep marine turbidity currents. The sandstone is interbedded with several types of non-reservoir facies, including frequent carbonate cemented intervals forming rather persistent lateral layers. Inverted 3D seismic identify intra reservoir acoustic impedance features indicating possible extensive reservoir heterogeneities which impact fluid flow, reservoir drainage and flooding patterns.

Reservoir simulation studies prior to field development sanctioning revealed that the recovery factor was very sensitive to the level of fluid transmissibility across the major acoustic impedance features. Although these transmissibilities could not be confidently estimated a priori to development sanctioning, having a fully compartmentalized reservoir was considered highly unlikely.

The Siri Field is currently developed with five long horizontal oil producers and two simultaneous water and gas (SWAG) injectors. Reservoir pressure information acquired during concurrent early stage development well drilling and production proved valuable during the interactive interdisciplinary detailed planning of subsequent development well trajectories and completion intervals.

Pressure sources integrated to provide reservoir scale dynamic formation characterization and to aid in the day to day reservoir- and production management comprise: Openhole formation testsDrill stem test"Advanced" cased hole formation tests (applying coiled tubing conveyed dual select firing heads)Permanent downhole pressure gaugesTractor conveyed production logging

This paper describes, how this multitude of pressure surveillance data have been integrated to evaluate and document: Field wide pressure communicationReservoir scale permeabilitiesCross flow severity associated with large dynamic pressure gradients along extended horizontal production wells

Furthermore, the information value from permanent downhole gauges is addressed.
Meeting the Challenge to Extend Success at the Pikes Peak Steam Project to Areas with Bottom Water
Authors: Wong F. Y. F. , Anderson D. B. , O'Rourke J. C. , Rea H. Q. , Scheidt K. A.
Published: December 2007

This paper provides a field review of the Pikes Peak steam project, showing key performance indicators of cyclic steam stimulation (CSS) and steam drive in non-bottom water. To test development over relatively thin bottom water (less than 5 meters), various steam processes were field trialed. Field pilot results from vertical well CSS, dual horizontal well gravity drainage, and a combination of vertical injectors-horizontal well producer are presented for comparison.

Based on field experience and numerical simulation input, CSS has been successfully conducted with economic steam-oil ratios (SOR) in areas with up to 4 meters of bottom water by injecting significantly larger steam slugs in what is termed a drive, block and drain process. In thicker bottom water, the ability to operate at constant pressure to prevent bottom water influx confers an advantage to the horizontal well approach. Followup field scale developments of some bottom water areas are described. Numerical simulation results indicate that pressuring up of a depleted steamflooded zone to be an optimum strategy for maximizing offset flank recovery. This is being implemented in the field by re-injecting produced vent gases.
PVT Properties and Viscosity Correlations for Gulf of Mexico Oils
Authors: Dindoruk Birol , Christman Peter G.
Published: December 2007

New empirical PVT correlations for Gulf of Mexico (GOM) oils have been developed as a function of commonly available field data. Correlations have been developed for: bubblepoint pressure,solution gas oil ratio at bubblepoint pressure,oil formation volume factor at bubblepoint pressure,undersaturated isothermal oil compressibility,

Oil Viscosity: dead oil viscosity,saturated oil viscosity, andundersaturated oil viscosity.

For the development of correlations, we have covered a wide range of data. More than one hundred pressure-volume-temperature (PVT) reports from GOM have been used in the development of correlations. Two of the published correlations, Standing, and Petrosky and Farshad correlations were tested using our GOM data set. Proposed correlations of this study predicted the PVT properties of GOM oils better than the correlations published in the literature, even when the coefficients of the published correlations are tuned. Using the correlations of this study, we have written a simple program that can generate PVT datasets for use in reservoir simulation. Laboratory measured differential liberation data for two different oil samples were also compared against our empirically generated differential liberation data.
Screenless Tip-Screenout Fracturing: A Detailed Examination of Recent Experience
Authors: Fan Y. , Looney M. D. , Jones J. A.
Published: December 2007

Texaco has been conducting screenless tip-screenout fracture to stimulate production in the Kern River field of California. During 1998–2000, more than 500 fracture treatments were pumped in some 200 wells. These treatments caused average oil production to nearly triple. This paper documents the results of the tip-screenout fracture treatments conducted over the past three years and presents a statistical analysis to determine how the production response is related to the treatment parameters. The goal was to identify the conditions that on average lead to the optimum production response.
Increasing Production with an Innovative Through Flow Line (TFL) Multi-Zone Completion Design for a Major Norwegian Operator
Authors: Østvik Egil , Hansen Helge Bjorna , Rasmussen Lars , Malmanger Eva Mette , Hydro Norsk , Tønnessen Sven Harald , Browne Paul L. , Williamson Jim
Published: December 2007

Norsk Hydro operates the Snorre Field in the Norwegian sector of the North Sea with a tension leg platform (TLP) and a sub-sea production system. The initial sub-sea wells were designed with completions that would allow through-flow-line servicing, and while the wells were functioning as designed, production had been declining. Therefore, Norsk Hydro felt that the completion concepts should be evaluated for new field developments. The ensuing investigation and development project led to a novel well completion concept, which is the first "intelligent well" subsea completion installation offshore Norway.

This innovative design changes retain the original through-flow-line (TFL) service technique system and subsea infrastructure without any modifications, maximize production by introducing 7-in. tubing, and include hydraulically operated inflow control devices.

The supplier and operator developed the concept during the winter 1998/1999 and designed the resulting system during spring 1999.

License approval for prototype development and qualification was given in the summer of 1999, and the system components were in-house tested at the supplier base in Dallas during the fall of 1999. A thorough system qualification was performed at an independent Norwegian drilling and well test center during spring/summer of 2000. The qualification included a full test-well installation and necessary intervention activities to prove the functionality of the concept. The system was qualified during the summer of 2000. The first subsea well installation was done at Snorre and put on production in December 2000. The well completion consisted of a 4-zone/interval design for improved reservoir management.

The concept principles also have application for other type wells on platforms where modifications to the wellhead and tree are not feasible.

The development process and qualification of the system has been conducted in a very short time period from idea to offshore implementation. This is mainly the result of a very focused personnel team with competent and dedicated personnel between supplier, operator, and 3rd party testing contractor.

This paper will discuss the improved system and testing that resulted from this project. The first new production system was installed in a side-tracked well, and the results of the completion will also be discussed.
Design and Deployment of an Intelligent Completion with Sand Control
Authors: Bixenman P. W. , Toffanin E. P. , Salam M. A.
Published: December 2007

Early results from intelligent completion installations show great promise for production optimization and control. The intelligent completion flow control valve is typically installed between isolation packers within the production zone. There have been installations with as many as four zones containing intelligent flow control devices. Several installations of intelligent flow control equipment have been in wells that require sand control, but these installations did not allow placement of the flow control devices within the production zone. The zones are completed with traditional sand control techniques, with each zone gravel packed or frac packed. After the sand face completion is in place, an upper completion is run into the well with a siphon string stabbed into the lower zone. A valve in line with the siphon string controls production from the lower zone. Production from the upper zones flows through the annulus between the siphon string and the upper completion into the casing annulus above the uppermost gravel-pack packer. A flow control valve is used to control the flow from that casing annulus into the production tubing. In this type of configuration, the practical limit for zones that can be controlled is two. An alternative technique has been developed that allows the placement of the flow control device within the production zone, so that more than two zones can be completed with intelligent flow control devices. As is the case for an intelligent completion in a cased and perforated well without sand control, the entire completion is run in one trip. Once the completion is in place, all of the intelligent completion devices are tested and then the packers are set. A through-tubing sand control tool is then run into the completion to perform the gravel packing operation in each zone. The paper discusses the completion design and presents an example of a field installation.
The Use of Fiber-Optic Distributed Temperature Sensing and Remote Hydraulically Operated Interval Control Valves for the Management of Water Production in the Douglas Field
Authors: Tolan Michael , Boyle Maurice , Williams Glynn
Published: December 2007

Unwanted water production has long been one of the biggest problems that the oil and gas industry has had to address in efficiently producing hydrocarbons. This paper describes how fiber-optic-distributed temperature sensing (DTS) has been used in conjunction with remotely operated hydraulic interval control valves (ICVs) as an economical management tool for controlling water encroachment. Used with intelligent well technology, this method provides interventionless control and selectivity of producing intervals using surface-actuated hydraulic ICVs so that unwanted water production can be managed more effectively to maximize oil recovery. Distributed temperature measurements at one-meter intervals in the wellbore provide data that assists in the determinations of zonal contribution and the identification in the change of fluid properties or water ingress.

This method was installed on the Douglas Platform in Liverpool Bay, United Kingdom. The completion was comprised of an ESP pump, hydraulic on/off disconnect, retrievable packers with hydraulic feed throughs and hydraulic ICVs. An optical fiber that acquires continuous distributed temperature data is installed into one of the hydraulic control lines that operate the hydraulic ICVs. Opto-electronic instrumentation on the platform allows distributed temperature data to be transmitted in real-time to a shore-based asset team.

The combination of fiber optics and hydraulic interval control valves provides a number of benefits:

The number of penetrations through tubing hangers and packers are reduced if required The fiber optic sensor is capable of gathering realtime logging data from multiple intervals without intervention The ICVs provide interventionless zonal control The disconnect system facilitates ESP workover and recompletion.
Hydroxyaminocarboxylic Acids Produce Superior Formulations for Matrix Stimulation of Carbonates at High Temperatures
Authors: Frenier W. W. , Fredd C. N. , Chang F.
Published: December 2007

Hydroxy-aminocarboxylic acids (HACA) including hydroxyethylethylenediaminetriacetic acid (HEDTA) and hydroxyethyliminodiacetic acid (HEIDA) possess some unique chemical characteristics. The most significant attribute is high solubility in acidic solutions; in addition, HEIDA is biodegradable. Other conventional chelating agents, such as ethylenediaminetetraacetic acid (EDTA) become insoluble in acid at pH values < about 4.0 and EDTA is slightly (0-5% depending on the test) biodegradable. The unusual characteristics of the HACAs have enabled the formulation of unique acidizing and scale removal systems that are being employed for cleaning and stimulating oil and gas wells.

In this current paper, we will describe the continuing development and testing of HACA materials as components of matrix acidizing formulations for stimulating carbonate formations at very high temperatures (400 °F). The pioneering work of Fredd and Fogler (SPEJ, 4(3) 1999) demonstrated that organic acids and chelating agents have unique attributes that lend themselves to efficient production of wormholes in many acidizing situations. We have applied the same techniques for determining transport and reaction kinetics, to stimulation fluids containing hydroxy amino chelating agents. Linear core-flood tests were used to study wormhole formation and rotating disk tests with calcite samples were employed to elucidate the kinetics and mechanisms of the dissolution over a temperature range of 65 to 400 °F. Carbonate formations are very difficult to stimulate at these high temperatures because mineral acids react much to fast to produce dominant wormholes, and are difficult to inhibit (corrosion control).

In addition, these new fluids will not require iron control agents to be added (they are effective iron complexers), and are easily inhibited to high temperatures (up to 400 °F) using minimal amounts of corrosion inhibitors.
NMR Measurements in Carbonates Samples and Core-Logs Correlations Using Artificial Neural Nets
Authors: Salazar J. P. , Romero P. A.
Published: December 2007

The Mara West Field reservoir in the Maracaibo Lake presents some challenges in petrophysical evaluation, which are related to the determination of the water saturations, porosities and permeabilities. The information extracted from conventional log data is not sufficient to fully evaluate the formation. This is due to the fact that these logs are affected by the presence of carbonates, difficulting the evaluation of porosities and other properties. In order to overcome this problem, Nuclear Magnetic Resonance technique has been used in the evaluation of core plug samples and further core logs correlations. Its advantage lies in the measurement of porosity independently of lithology and pore distribution and in the calculation of permeability using parameters such as Nuclear Magnetic Resonance porosity, T2 cutoff, free fluid index and bound water volume.

The present work shows a very good correlation between Nuclear Magnetic Resonance data and conventional data extracted from core plug samples. It also shows how the implementation of a new equation for the estimation of permeability, provides an increment of the correlation coefficient from 0.36 to 0.81 obtained from the Nuclear Magnetic Resonance permeability Vs Klinkemberg permeability plot.

In order to complete the log information in the cored well and in a neighbor well, Artificial Neural Nets based on the backpropagation algorithm have been applied, generating the so called pseudologs (synthetic logs). To obtain the pseudologs of NMR porosity, gamma ray, resistivity and neutron logs have been used as input, while the core plugs value for NMR porosity and permeability as output. The results show a very good match between the existing data and the artificial neural net output in the validating data set.
A Model-Based Interpretation Methodology for Evaluating Carbonate Reservoirs
Authors: Ramakrishnan T. S. , Ramamoorthy R. , Fordham E. , Schwartz L. , Herron M. , Saito N. , Rabaute A.
Published: December 2007

Carbonate rocks are diverse, and their pore space complex. Petrophysical evaluation of carbonates with techniques developed for siliciclastic environments often fall short.

In this paper, we present a new methodology that combines diverse texture and facies sensitive measurements. The method parametrizes the pore structure in terms of a multiporosity system of fractures, vugs, inter- and intra-granular porosities, and evaluates the parameters from the measurements. The process is based on physics and relies minimally on empirical correlations.

The first step is to separate the fracture from the matrix using borehole images and then quantify mineral volumes and porosity through nuclear magnetic resonance (NMR) and/or nuclear logs with new mineral standards. Next, we classify the lithology with a self-organizing-map (SOM) algorithm using a vector of log-inputs. Following this, the vug fraction is estimated using shear modulus data and borehole image analysis. Finally, we separate the inter- and intragranular components using NMR data. This analysis includes molecular diffusion between different pore types. The NMR processing scheme also depends on lithology. The porosity components and the relevant length scales enable us to predict resistivity and permeability using an effective medium theory in an internally consistent manner.

Our interpretation methodology was validated successfully with core/log data from the Middle East. The facies ranged from mudstone to grainstone.
Utilizing Magnetic Resonance Logging for Improved Formation Evaluation in the Mediterranean Thinly Laminated Gas Bearing Formations: A case Study
Authors: Nashaat Mohamed , Sallam Yassin , Elsherif Ahmed
Published: December 2007

The Mediterranean is considered the future frontier for the gas development in Egypt. Rashid Petroleum Company (RashPetco) has recently achieved good results in the Mediterranean where a gas bearing formation was discovered and evaluated using the latest technology in formation evaluation. Standard open-hole measurements were used for porosity and water saturation estimation.

Recently, several wells were drilled and evaluated using the conventional methods. In one of the wells, an interval was evaluated as a body of shale and silt. The standard measurements gave no indication of pay zone in this body and it was not considered to contribute in the estimation of the total reserves. This body was reevaluated using the high-resolution technologies of Magnetic Resonance and Borehole Imaging measurements. Sandstone laminations were discovered and properly evaluated. The productivity of the sand streaks was established through the high-resolution permeability of the Magnetic Resonance logging. This productivity was proven by the utilization of Packer Module formation tester. The body was tested and was proven to be productive. Because of the new interpretation, the net pay was re-calculated in this shale body and was added to the total pay. Consequently, an increase in the proven gas in place was achieved. The technique of Density Magnetic Resonance (DMR) was used to properly evaluate the formation porosity and permeability.

Moreover, a water bearing sandstone was re-evaluated using the Magnetic Resonance logging and was proven to have residual gas which confirmed the surface seismic results. This confirmation changed the strategy for future drilling in British Gas.
The Integration of Capillary Pressures and Pickett Plots for Determination of Flow Units and Reservoir Containers
Authors: Aguilera R. , Aguilera M. S.
Published: December 2007

The concept of flow (or hydraulic) units and reservoir containers has been used in the oil industry with a good deal of success during the last few years. The process or delivery speed k/f can be used in many instances to define a flow unit. Correlation of flow units between wells helps to establish reservoirs containers and to forecast reservoir performance.

This study shows that a Pickett crossplot of effective porosity vs. true resistivity (in some cases apparent resistivity or true resistivity affected by a shale group) should result in parallel straight lines for intervals with constant process speed k/f. The slope of the straight lines is related to the porosity exponent m, the water saturation exponent n, and constants in the absolute permeability equation. From the straight lines it is possible to determine directly capillary pressures and pore throat apertures for each flow unit at any water saturation. Pore throats at 65% water saturation compare very well with Winland r35 values. The method has not been published previously in the literature.

Building lines of constant k/ϕ allows displaying complete capillary pressure curves on the Pickett plot including regions that are and are not at irreducible water saturation. Previous empirical methods for determining absolute permeability of a given interval assume that the water saturation is at irreducible conditions.

This paper presents a technique that allows estimating absolute permeability even if the interval contains moveable water.

The use of this technique is illustrated with previously published data from the Morrow sandstone in the Sorrento field of Southeastern Colorado and carbonates from the Mission Canyon formation in the Little Knife field of North Dakota.

It is concluded that flow units can be determined reliably from the integration within one single log-log graph of Pickett plots, capillary pressures, pore throat apertures and Winland r35 values. The correlation of the flow units between wells leads to the definition of reservoir containers.
Effects in the Determination of Oil Reserves Due to Gravitational Compositional Gradients in Near-Critical Reservoirs
Authors: Jaramillo Juan M. , Barrufet Maria A.
Published: December 2007

Several factors, such as gravity, temperature, type of reservoir fluid, geological structure, accumulation process, etc., may have important effects on the spatial compositional variation of hydrocarbon fluids in reservoirs.

Compositional gradients, which may be considerable in near-critical reservoirs, can have a profound impact on the estimation of initial in-situ hydrocarbons, the prediction of oil/gas contact location (OGC), and more important on the reservoir development strategies.

Some reservoirs have producing intervals with thickness that cover hundreds of meters from top to bottom, and sometimes even more than 2,000 meters. Over such a thickness, due to gravitational segregation, the mole fraction of the lighter components decreases with depth, while the mole fractions of the heavier components increase from the top to the bottom of the reservoir. Modeling the thermodynamic behavior of these fluids requires a properly tuned EOS capable of reproducing the available PVT data and the gravitational compositional gradation.

We studied a volatile oil from the Cusiana Field in Colombia. PVT reports consisting of constant composition expansion (CCE) and constant volume depletion (CVD) tests were used to calibrate the fluid mo del and the EOS parameters. We used the Peng Robinson EOS with volume translation and Whitson's methodology for defining and characterizing the pseudocomponents.

The result of this study addresses the discrepancies in original hydrocarbon volumes that take place when the compositional gradient is not considered. Without considering a compositional gradient, the original oil and gas in place can be either over or underestimated depending upon the depth at which the sample is taken. We show that we can select a reference sample composition, corresponding to a certain depth, such that this can be used without compositional gradient and the estimates of the original hydrocarbons in place are equivalents to those obtained with compositional gradient.

We provide guidelines and procedures to evaluate the effect of isothermal gravitational compositional gradient in the determination of in-place hydrocarbon content for volatile oil and gas condensate reservoirs.
Pulsed Neutron Spectroscopy Handles Saturation Monitoring In Complex Lithology Long Cased Hole Horizontal Production Wells
Authors: Borch Carsten , Whittaker Andrew Colin
Published: December 2007

The Siri Field on the Danish Continental Shelf is characterized by low-resistivity pay and porosities exceeding 30 PU. The reservoir sands are fine to very fine grained, well sorted with abundant iron-rich glauconite and chlorite. The microporous glauconite reduces the effective porosity and permeability and causes high initial bound water saturations.

Reservoir drainage is based on water and gas flooding (SWAG injection). Producing field water-cut increases rapidly in the horizontal producers due to severe bottom aquifer coning and later injection water breakthrough. The oil production rate is constrained due to limited liquid handling capacity. Water management is hence, a primary focus area.

Prior to initiating remedial workover operations, wireline tractor conveyed production inflow profiles and pulsed neutron capture gamma ray surveys were acquired.

In sigma saturation monitoring a pulsed neutron source allows the decay rate of capture gamma rays to be measured. The decay rate is inversely proportional to the formation sigma, which is a linear combination of the sigma values of the rock matrix and fluid filled porosity. Knowing the matrix sigma, oil sigma, water sigma, and total porosity, the log sigma can be converted to formation saturation.

The complex mineralogy of the reservoir sand with abundant and variable amounts of iron-rich glauconite significantly impacts the matrix sigma. Before sigma saturation interpretation can be made, the lithology needs to be determined more accurately than possible from standard open hole logs. A novel through casing pulsed neutron logging technique permitted well lithology determination. Using the spectral signal of the pulsed neutron capture gamma rays, a number of key matrix elements were quantified, converted to a matrix lithology, and then finally combined into a synthetic matrix sigma.

This paper describes, how a single pulsed neutron tool operated in two modes (spectroscopy and sigma) permitted quantitative lithology interpretation and saturation monitoring in a complex formation environment.
Advances in LWD Nuclear Magnetic Resonance
Authors: Drack E. D. , Prammer M. G. , Zannoni S. , Goodman G. , Masak P. , Menger S. , Morys M.
Published: December 2007

A second generation of LWD Nuclear Magnetic Resonance (NMR) tools has been developed and commercialized. These MRI-LWD* (Magnetic Resonance Image - Logging While Drilling) tools extend the technology by providing key improvements in data quality and operational efficiency. Improvements include: automatic mode switching, better vertical resolution, improved signal-to-noise ratio (SNR), real-time data transfer, built-in log quality control, increased battery life, and extended environmental ratings.

The paper also examines the context for the deployment of this system and the expanding role of NMR in formation evaluation. MRI-LWD belongs to a family of NMR tools which includes logging-while-drilling, wireline open-hole logging, formation testing/fluid sampling, and laboratory core analysis.
The Use of Real-Time and Time-Lapse Logging-While-Drilling Images for Geosteering and Formation Evaluation in the Breitbrunn Field, Bavaria, Germany
Authors: Rohler Hendrik , Bornemann Ted , Darquin Alexis , Rasmus John
Published: December 2007

Six horizontal wells were drilled into the Tertiary Chatt Sand reservoir of the Breitbrunn gas field in Bavaria, Germany. The purpose of this campaign was to develop part of the depleted reservoir into a gas storage sand. A detailed geological and petrophysical study was prepared prior to drilling and resulted in the identification of high quality reservoir layers that were targeted by the horizontal wells. Despite the simple anticline structure of the field, geometric drilling was ruled out due to remaining geological and directional uncertainties. The geosteering approach adopted relies on real-time GeoVision Resistivity (GVR·) resistivity images, which were used for the first time ever during this drilling campaign. The image data are compressed downhole and transmitted to the acquisition computer on the rig where they are decompressed and analyzed. The images allow the precise placement of the borehole relative to the geology, which "keeps the bit in the sand". Layer heterogeneity like tight streaks, concretions or patchy porosity can be identified as such, and are not interpreted as a different layer entered by the hole, which would lead to a wrong geosteering decision. Logging-While-Drilling (LWD) azimuthal data are acquired during drilling and also during wash-down passes which follow a bit change. A comparison of these time-lapse data sets can provide invasion profiles through time and around the borehole.
A New Generation Crossed Dipole Logging Tool: Design and Case Histories
Authors: Kessler Calvin , Varsamis Georgios L.
Published: December 2007

With the increase in deepwater exploration and production and the advances in logging-while-drilling formation evaluation (along with the high rig costs) the wireline formation evaluation is often limited to only one drill pipe conveyed logging run. A new monopole and crossed dipole acoustic logging tool was designed for the drill pipe conveyed environment. The robust mechanical design does not limit this sonic tool to the bottom of the tool string. NMR and pump-through formation testing tools can be located in the logging string below this tool on drill pipe-conveyed logging, or e-line conveyed logging.

This tool was designed utilizing a systems approach and most of the functions of the tool are surface programmable. For example, the pulse shape, duration, amplitude, and frequency of the on-depth crossed dipole bender bar sources is programmable. Likewise, the level of the monopole output signal is also surface selectable. The digitization of the 96 waveforms of data per depth sample is programmable for number of samples, sampling interval and waveform compression. With 96 waveforms per depth sample, a logging speed of approximately 1800 ft/hr (30 ft/min) can be achieved with a quad-combo logging suite acquiring sonic data at two samples per foot.

Case histories from a variety of formations demonstrate the tool's capability to obtain monopole P wave data, monopole refracted shear data, crossed dipole flexural wave slowness, and anisotropy. The following representative formations are included in the case histories: near-zero porosity carbonate with refracted shear wave slowness and flexural wave slowness of less than 100 μsec/ftporo-plastic Gulf Coast sandstones and shales with flexural wave travel times exceeding 700 μsec/ftformations with natural fractures that are detectable by the cross dipole flexural wave slowness and confirmed with open hole image dataa shale section with approximately 650 psi of stress anisotropy
Evaluation of CO2 Gas Injection For Major Oil Production Fields in Malaysia - Experimental Approach Case Study: Dulang Field
Authors: Md. Zain Zahidah , Kechut Nor Idah , Nadeson Ganesan , Ahmad Noraini , Raja D M Anwar
Published: December 2007

In meeting the challenge to improve oil recovery through implementation of IOR techniques, Dulang field was selected to study the possibility of CO2 injection as a potential recovery method. Dulang was chosen as the candidate because of the complete suite of information on this field and the availability of CO2 source within Dulang and nearby fields. The work focused on characterizing the oil and oil - CO2 interactions that was performed through phase behavior studies, vaporization test and displacement tests.

Studies conducted indicates that at the reservoir temperature of 215°F, CO2 injection would not be able to achieve miscibility with the crude oil at the current reservoir pressure, or even if the pressure is increased to the initial reservoir pressure. Equation-of-State (EOS) model also shows that the Multiple Contact Miscibility Pressure (MCMP) for CO2 and produced hydrocarbon gas is 3230 psig and 3340 psig respectively. This pressure is significantly higher than the initial reservoir pressure of 1800 psig.

Vaporization of Dulang crude by pure CO2 and the CO2-rich produced gas was studied. The laboratory study suggests significant vaporization of 15% of the stock tank oil with pure CO2. However, based on Equation of State, the vaporization ranges from 2 - 5 % with produced gas at operating reservoir pressure of 1400 - 1800 psig.

In view of the above, the potential recovery process is an immiscible process using produced gas containing high CO2 for cost optimization. In addition, the water alternating gas (WAG) process may improve mobility control and sweep efficiency. Detail studies involving WAG Composite Core, G & G Modeling and Numerical Simulation are currently on-going for identified location of a pilot project.
EOR Possibilities for Development of a Mature Light-Oil Reservoir in Oman
Authors: Babadagli T. , Al-Bemani A. , Boukadi F. , Iyoho A. W.
Published: December 2007

This paper presents the development plan using EOR techniques for a sandstone reservoir containing very light oil (45 oAPI, 0.5 cP at reservoir conditions) located in Oman. Due to low permeability (0.1 to 5 mD) of the upper part of the reservoir (Upper Haushi Sand, UHS), recovery factor was very low. However, original oil in place is quite significant in this formation and EOR application was targeted to increase the recovery factor. On the other hand, reservoir pressure is still high due to strong aquifer support. Another zone of high permeability (100-300 mD, Sand Drain, SD) has been watered out by the strong aquifer influx. Being operated by a small size oil company, the main concern was the economics – capital and operating expenditures. After a screening process the optimum solution was found to be nitrogen injection to overcome the low injectivity. The low viscosity of oil and relatively low cost of injectant also make the injection of nitrogen a favorable application.

The response of the two formations (UHS and SD) to nitrogen injection was tested in laboratory by injecting nitrogen into oil saturated core samples. The recovery obtained by immiscible displacement of oil was as high as 40 % in the tight UHS. Similarly, tests were carried out to understand the response of nitrogen injection into already waterflooded high permeability SD zone. The recovery was found to be 5 to 10 % after 75 % waterflood recovery. Next, the nitrogen injection performance was studied using a full-scale field simulator. After obtaining a history match, the option of using abandoned downdip wells as injectors and the updip wells as producers were evaluated. Relative permeability curves generated using the laboratory tests were applied and different injection scenarios were tested through a series of simulation runs. Also, the possibilities of injecting air without purifying from the oxygen were discussed from the economical, technical, additional oil recovery and safety points of view.
Determination of Residual Oil Saturation in A Carbonate Reservoir
Authors: Tang Joseph , Zhang Pei-Xin
Published: December 2007

Single-well tracer testing has been widely accepted as a standard method for measuring residual oil saturation to waterflood. Residual oil saturation is an important parameter in the evaluation of tertiary oil recovery potential for depleted reservoirs. At an advanced stage of depletion, Leduc, a Canadian carbonate reservoir, has been considered as a candidate for enhanced oil recovery. As part of the evaluation process, single-well tracer tests were conducted at two watered-out producers to determine residual oil saturation to waterflood. The tracer production profiles were found to be highly skewed with long tails and early arrival times, which are typical for carbonate reservoirs. Two different models, namely a double-porosity model where tracer could distribute between the flowing and non-flowing pores through mass transfer and a single-porosity model where a fictitious water drift rate was assumed in the test zone, were used to interpret the data. It was found that either model could match the data to the same degree of accuracy regardless of the flow mechanisms assumed and the residual oil saturation derived from these two models were 35% and 38% respectively. This demonstrates the robust nature of the test that the non-uniqueness of the match does not affect residual oil saturation determination. The residual oil saturation determined by simple analytical models including mass balance method, peak method and mean retention volume method were all in the range of 34% to 38%, in excellent agreement with the simulation results. As well, the Sorw obtained by the SWTT method compared favorably with those determined by interwell tracing (35%) and sponge coring (33%).
Pressure-Dependent Pore Volume Compressibility – A Cost Effective Log-Based Approach
Authors: Ong Seehong , Zheng Ziqiong , Chhajlani Richin
Published: December 2007

This paper presents an innovative log-based method of determining pore volume compressibility as a function of pore pressure depletion. The approach considers changes in reservoir stress associated with pore pressure change (stress path) and incorporates constraints that ensure deformations are within elastic bounds. The approach incorporates the effect of stress anisotropy by using elastic moduli derived from stress-strain curves under simulated triaxial loading conditions. The triaxial condition pore volume compressibility was then converted to that of unaxial strain equivalent, which best describes the existing reservoir characteristics. The proposed methodology is particularly useful for predicting pressure-dependent pore volume compressibility where core specimens are either not available or in situations where laboratory measurements are prohibitively laborious and time consuming.

For input, the method requires bulk modulus, compressive strength and other mechanical properties that characterize an elastic material, preferably predicted using a log-based mechanical property algorithm in order to generate a foot-by-foot profile of pore volume compressibility. A continuous profile of uniaxial strain pore volume compressibility with depth from log provides quick assessments of pore volume compressibility variations across the reservoir intervals. It is also useful and cost-effective for constraining pore volume compressibility of all the reservoirs penetrated by the well (and logged) but with only limited core data available for calibrations.

The example shallow oil well data illustrates that pore volume compressibility decreases with decreasing pore pressure (or increase effective stress). An inverse pore volume compressibility to strength relationship was also observed. It was also observed that pore volume compressibility decreases with increasing porosity until the effective porosity reaches a critical minimum value. At porosity higher than the critical value, the pore volume compressibility increases with increasing porosity. This may suggest that reservoirs with a porosity less than the critical value are more likely to be under pressure drive, while reservoirs with porosity higher than the critical value are more likely to be under compaction drive.
Research of Polyacrylamide Gel Application for Water Shutoff in High Temperature Fractured Granite Basement Reservoirs
Authors: Tung Nguyen Phuong , Hung Pham Viet , Vinh Ngo Quang , Long Bui Quang Khanh
Published: December 2007

Water shutoff and sweep efficiency improvement in crude oil production from high temperature fractured granite basement reservoirs, as White Tiger, have been poorly studied. For finding gels stable in severe working conditions like high temperature, high-pressure etc, variety compounds of polyacrylamide with inorganic and organic crosslinking agents have been tested. The effects of temperature, polymers, crosslinkers, brine salinity and pH on gelation and stability were found.

Base on the obtained results, proposed by the authors gelant compositions could be effectively applied for water shutoff in production wells of high temperature fractured granite basement reservoirs.