bluuebunny/crossref_metadata_2025 huggingface dataset:
Introduction to a Method to Obtain Formation Pressure by Pressure Build-Up Curves and Some Characteristics of Formation Pressure in Multi-Zone Heterogeneous Reservoirs of Daqing Oil Field
Authors: Wang Demin , Sun Yingjie , Tang Xuping , Wang Gang
Published: December 2007

This paper introduces the theoretical basis, derivation of the formulas and actual procedures of a method to obtain formation pressure by pressure build-up curves. The formation pressure can be average pressure in the drainage area, average pressure at the boundary, pressure when there are faults near the well, pressure for closed boundary conditions and water drive (with different injection – production ratios). This method is quite versatile, accurate and simple in procedure. Daqing Oil Field has used this method for more than 40 years to calculate formation pressure more than 1 million times.

Daqing Oil Field is very heterogeneous, has multi-zones and the zones are not very continuous between wells. The characteristics of formation pressure of this type of reservoir are quite different from that of homogeneous single-zone reservoirs. Field data and history curves are shown to point out the special characteristics of formation pressure of this type of reservoir.
Fast Computation of Effective Properties for Two Phase Flow Problems
Authors: Nomura M.
Published: December 2007

The current requirement of geologic detail to be built into reservoir descriptions has been exceeding the computational capabilities of reservoir simulation due to a need of huge number of simulation grids. This has motivated the development of a variety of upscaling techniques for flow simulation.

This paper presents an efficient upscaling method effective for an oil-wet heterogeneous reservoir, which offers a means of simulating multiple geostatistical realizations. A new effective permeability correlation is developed through application of one of the non-parametric regression techniques to the results of intensive numerical experiments. The developed empirical correlation enables us to compute effective permeabilities fast and accurately for a wide variety of heterogeneous permeability fields from layered to random system and can be easily extended for averaging two-phase flow properties under viscous limit or capillary limit.

The paper describes the developed technique in detail and demonstrates how the overall upscaling procedure can be speeded up with the desired accuracy.
Comparison of Specific Energy Between Drilling With High Power Lasers and Other Drilling Methods
Authors: Graves Ramona M. , Araya Anibal , Gahan Brian C. , Parker Richard A.
Published: December 2007

Specific energy is often used as a measure of a drilling methods performance. Specific energy as defined in this paper is the amount of energy required to remove a given volume of rock (energy/volume). This is a normalization method used to compare the efficiency of one rock destruction technique to another. This paper compares specific energy between drilling with high power lasers and other drilling techniques such as traditional rotary and other novel methods such as water jets.

Specific energy calculations made from laboratory measurements taken using four high power lasers, are compared to specific energy calculations reported in the literature. Although many other rock types were lased in this research, all comparisons are made on Berea sandstone, as it is the most commonly tested rock. A discussion of how the sample type, shape of test sample, and experimental conditions effect the calculations and results is included.

It was found that there could be, and probably is, confusion caused by the way that specific energy is defined and calculated. The definition of specific energy, as used in this paper, is often compared to specific kerfing energy that is defined as power per kerf depth multiplied by the speed the cutting mechanism is moving across a rock surface. It was also found, by reviewing published work, that there have been many comparisons made in the literature that did not take into consideration such things as rock type and shape. Experimental conditions such as the atmosphere where the "cutting" tool and the rock interact have not been accounted for when many of the previous comparisons were made. Sample size in relationship to power density has also not been accounted for.
Fateh Field Sea Water Injection - Water Treatment, Corrosion, And Scale Control
Authors: Nassivera M. , Essel A.
Published: December 2007

Introduction

In May 1974, Dubai Petroleum Company started the injection of seawater in the Fateh Mishrif reservoir. Hereafter is described the water treatment, the corrosion control through the waterflood plant and the subsea water lines, the scale prevention in the injection wells and the prevention in the injection wells and the scale control in the producing wells.

WATER TREATMENT

The seawater is lifted from 100' below the surface through a lifting caisson common to three lifting pumps. Two electro-chlorinators provide a hypochlorite solution in order to kill the bacteria and marine organisms in the lifted water. The hypochlorite solution is injected through a distribution ring located at the bottom of the lifting caisson, therefore all the lifted water is treated. The electro-chlorinators can be operated either automatically or manually to insure a chlorine content of 1 to 1.2 mg/l in the lifted water.

The average total suspended solids (T.S.S.) in the raw water is 1 mg/l with a maximum of 4 to 5 mg/l. From the caisson, the water goes through strainers then to the upflow sand filters. Before entering the filters a coagulant is injected into the water. The injection of bentonite as a filter aid was found unnecessary and has been discontinued. After filtration the TSS is less than the specified 0.2 mg/l. The TSS is determined by filtration on a 0.45 millipore filter. To meet the TSS specification the filters are flushed every 48 or 72 hours according to the raw water TSS.

A defoamer is added to the water before entering the vacuum towers where the water is deaerated by vacuum. The remaining oxygen content is less than 0.02 mg/l. Since the water injection was started it has never been necessary to add an oxygen scavenger to meet the specified oxygen content of 0.02 mg/l. The filtered deaerated seawater is then injected in the Fateh Mishrif reservoir through 24 wells. Once a week a bactericide is injected as a batch treatment upstream of the sand filters to kill the remaining bacteria. Two different bactericides are used alternatively.

The oxygen content of the water is monitored continuously. The iron, hydrogen sulfide and sulfate reducing bacteria contents are regularly monitored on the waterflood plant and on the remote platforms to determine adjustments necessary in the water treatment.

CORROSION

The raw seawater contains an average of 6.5 mg/l of oxygen, 42 to 44,000 mg/l of dissolved salts and has a low resistivity of 17.60 ohm-cms; therefore it is very corrosive. The lifting caissons, the strainer bodies and the lifting pump discharge headers are made of epoxy lined carbon steel. The lifting pumps are composed of stainless steel and monel which are corrosion resistant. From the discharge header to the vacuum towers, vinyl ester resin fiberglass reinforced piping has been used successfully.

The vacuum towers are lined with rubber. Downstream of the vacuum towers the oxygen content of the water is less than or equal to 0.02 mg/l.
Active Feedback Control of Unstable Wells at the Brage Field
Authors: Dalsmo M. , Halvorsen E. , Slupphaug O.
Published: December 2007

In this paper we will present new results on stabilization of horizontal wells with gas lift. The stabilization is achieved by a novel dynamic feedback control solution using the production choke at the wellhead. The primary input to the dynamic feedback controller is a measurement of the downhole pressure.

The field results to be presented are from the Brage field operated by Norsk Hydro in the North sea. Production at Brage began in 1993 and the field went off plateau in 1998. As the production has decreased, the problems related to unstable production from some of the wells have escalated steadily.

The results from the extensive field tests on the Brage wells are very promising. The tests have confirmed the stabilization feature of the control solution. The pressure and flow variations have been dramatically reduced, and it is possible to produce the wells at a lower downhole pressure leading to increased production.
Downhole Fiber-Optic Multiphase Flowmeter: Field Installation
Authors: Kragas Tor K. , Myers Gregory A. , Purdy Gill E. , Dria Dennis E. , Rambow Frederick H.
Published: December 2007

In October of 2000, a downhole fiber optic flowmeter was installed in Shell's Mars A-18 well in deepwater Gulf of Mexico. The production tubing-deployed system was installed to a measured depth of 21,138 feet in a highly deviated section of the well, immediately above the producing zones, in 2940 feet of water. This installation represents the first allfiber optic, multiphase flowmeter system deployed in a commercial well.

The fiber optic flowmeter delivers real-time measurements of downhole pressure, temperature, flow rate, and phase fraction. It is completely non-intrusive and contains no downhole electronics or moving parts. The meter requires only one wellhead penetration and is deployed on a single fiber optic cable with the production tubing string during well completion, in a manner similar to conventional, electronic downhole monitoring systems. Installation of the flowmeter at Mars was achieved as planned with no additional rig time required. In fact, the entire well completion operation was finished ahead of the budgeted schedule. This in large part is attributable to pre-job planning and preparations for the entire operation.

Performance of the flowmeter at Mars exceeded expectations and demonstrates the value of real-time downhole production data. Along with providing the production engineer with downhole pressure and flow rate data to control draw down while the well was being ramped up, data from the flowmeter provided other valuable information such as a temperature and pressure profile of the well during run-in-hole, well behavior during cleanup, and well productivity data.
A Case Study: Field Development Plan for a Highly Overpressured Gas Reservoir in China by a Multidisciplinary Consulting Team
Authors: Li Haiping , Xiong Hongjie , Wang James , Broetz Rolf J. , Azoba Hilary , Ryer Thomas A. , Miller Gary D. , Rahn Tami Chism , Wiltgen Nicholas A. , Robinson Brad M. , Kugler Ralph L. , Lee Donald W. , Plumb Richard A. , Martin Ron , Spivey John , Sun Longde , Song Wenjie
Published: December 2007

Operating companies generally produce their own field development plans (FDPs). Schlumberger Data and Consulting Services, a consulting group within an oilfield services company, was hired by PetroChina to perform a multidisciplinary integrated study on a highly overpressured gas reservoir, the Kela 2 field in the Tarim basin. The field has reserves exceeding 10 Tcf and will provide much of the gas for a major pipeline crossing China from the Tarim basin to Shanghai. The study consisted of building comprehensive geologic and reservoir models, estimating reserves, performing dynamic production and performance analyses on the reservoir, and providing an optimal FDP, which includes the drilling and completion designs, production engineering, reservoir monitoring and management, optimal implementation methods, and best practices.

This paper describes a comprehensive FDP technical approach and workflow designed to ensure both seamless integration of the disciplines and high-quality work. The technical approach incorporates the construction of a database, geological reservoir and mechanical earth models, a reservoir dynamic model, a single-well model, a development design model, and an economics and risk model. The paper summarizes our experience in assembling a multidisciplinary team, promoting effective teamwork, and quality control (QC).
Harmonic Testing for Continuous Well and Reservoir Monitoring
Authors: Hollaender Florian , Hammond Paul S. , Gringarten Alain C.
Published: December 2007

Harmonic testing for obtaining dynamic reservoir information was first proposed some thirty years ago. Although not much used in the oil industry, interest in the method is revived periodically, mostly for the determination of skin effect and near-wellbore permeability.

This paper looks at the practical aspects of using periodic rate variations for testing oil wells. It is shown that such tests can provide the same information as conventional well tests and can be interpreted in the same way. Their main advantage is that they do not require fluids to be brought to surface in exploration or early appraisal testing, or wells to be shut-in in production testing. They also provide data that are less affected by measurement errors and wellbore effects such as multiphase flow or phase redistribution. The main limitation is that, for the same radius of investigation, harmonic tests are significantly longer than conventional tests. Consequently, they cannot be used for reservoir characterization in exploration and appraisal wells. They appear well suited, however, for monitoring reservoir changes from production wells.
A Model for Foam Generation in Homogeneous Media
Authors: Kam S. I. , Rossen W. R.
Published: December 2007

Foam is a promising means to reduce gas influx into oil wells, control gas flow in improved oil recovery processes, direct acid flow in matrix acid well treatments, and improve the efficiency of environmental-remediation processes. Recent laboratory research in a wide range of porous media shows that creating foam in steady flow in homogeneous media requires exceeding a minimum pressure gradient. Data fit trends predicted by a theory in which foam generation depends on attaining sufficient ∇p to mobilize liquid lenses present before foam generation. Data show three regimes: a coarse-foam regime at low ∇p, strong foam at high ∇p, and, in between, an transient regime alternating between weaker and stronger foam.

Here for the first time a population-balance foam model incorporates bubble-creation function that depends on pressure gradient. The new model reproduces the three foam regimes seen in the laboratory, the abrupt occurrence of foam generation at a threshold velocity or pressure gradient, hysteresis in experimental results, the interplay between foam stability and foam generation, the effect of injected liquid fractional flow on foam generation, and foam behavior in the high-quality and low-quality steady-state strong-foam regimes. The details of the lamella-creation function have little effect on rheology of strong foam, which is controlled by other mechanisms. The predicted fractional-flow curves are complex. This model is a necessary step toward quantitative prediction of foam performance in the field.
Simulating Foam Process for a Venezuelan Pilot Test
Authors: Chalbaud C. A. , Moreno R. A. , Alvarez J. M.
Published: December 2007

Foams have been used routinely worldwide to divert acid in well stimulation treatments and to divert gas flow in improved-oil-recovery projects. However, the complexity of foam behavior has represented a strong obstacle in understanding and modeling such processes.

In 1999 Alvarez et al1 proposed an unified model for steady-state foam behavior at high and low qualities called "fg* model". This model explains the presence of two different foam-flow regimes identified by Osterloh and Jante2 in 1992. The fg* model is based on experimental laboratory data at room temperature.

The present study shows experimental data confirming that fg* model also applies at reservoir conditions (temperature, pressure and permeability close to the field). This fact has never been reported before. The experiments were designed to characterize steady-state nitrogen foam flow by measuring pressure gradients in Berea sandstone over a wide range of gas and liquid velocities and fractional flows. This study also presents the assumption that the critical surfactant concentration exists, below which the foam becomes weaker or unstable32. This critical variable was determined at reservoir conditions.

The experimental data were used to validate the foam model using a commercial simulator (STARS™), taking into account the parameters related to surfactant concentration, water saturation, capillary number and the reference mobility reduction factor. This simulation is used as part of the planning of a future pilot test in the Lagocinco field in the Maracaibo Lake, Venezuela.

Experimental work, such as that presented in this paper, gives support to the fg* model and allows choosing in advance, optimal foam treatment conditions (e.g. surfactant concentration and foam quality) for a particular gas diversion project, obtaining a more cost-effective field operations and determining the viability of a gas or acid diversion project.
Accurate Full-Bore Acoustic Densometer for Use with Proppant-Laden Stimulation Fluids at High Pressures
Authors: Birchak James R. , Vickery Curtis M. , Morgan Ronnie G.
Published: December 2007

Some areas of the globe with high oil and gas well drilling activity do not permit surface equipment that contains any type of radioactive source. The continuing concern with using radioactive sources in oilfield service equipment has led to the development of a new design for an acoustic densometer that will function accurately under the conditions required by stimulation pumping operations. Accurate metering of fluids containing high concentrations of materials such as frac sand, ceramic proppants, or other solids are an integral part of successful stimulation treatments of oil and gas wells around the world. Previous designs of acoustic densometers were not satisfactory for use at high pressures or were eroded excessively by the solids-laden fluids employed in hydraulic fracturing operations.

This new densometer design is able to handle full-bore flow at high pressures and to meet or exceed the accuracies of current in-line radioactive (R/A) densometers. In the paper, we will discuss the technical approach used to make the measurements. Extensive full scale test data will be shown for comparisons using three sand sizes (12/20, 16/30, and 20/40) in a water based gelled fluid with proppant concentrations of zero (no sand) up to 14 lb sand added per gallon.
A Method for Computing Fast and Accurate Analytical Gradient: the Key for Routinely Performing Efficient 2D and 3D Resistivity Inversions
Authors: Terpolilli P. , Ventre J. , Touron F. , Ramos I.
Published: December 2007

This paper consider several issues related to the inversion of resistivity log curves.

After choosing an initial guess, the inversion process needs to know exactly how to modify the earth resistivity map in order to obtain better computed curves. If we define the cost function as the square of the norm of the difference between the computed and the measured curves, the gradient map provides this piece of information. Only an analytical determination of this gradient map is efficient enough for an accurate solution. However, the additional computing time has to be reasonable. This paper includes an original method to determine an accurate first guess and a new method to compute efficiently the gradient of the cost function. Some numerical figures in CPU time are given for the computation of the gradient and for sensitivity analysis as well..
A Case Study of Long-Term Production Enhancement Derived from Usage of Organo-Borate Crosslinked Fracturing Fluids
Authors: Wood William D. , Brannon Harold D. , Ault Marshall G. , Matson Ronald P. , Carman Paul S.
Published: December 2007

Over the past 12 years, a significant number of wells in fields across the United States have been fracture stimulated with advanced organo-borate crosslinked fluids. This case study examines the production enhancement benefits that have been realized, as compared to more conventionally treated offset wells. Conventional treatments are defined as treatments that may consist of mono-borate or organo-metallic crosslinked fluids. Several case histories and offset comparisons were presented in the original SPE Paper 22838. This paper will provide a 10-year follow-up of those wells, presenting their long-term production benefits acquired from the use of organo-borate crosslinked fluids. In addition to the presented case histories from two subsequent SPE Papers, production data from an available pool of over 4000 wells, existing in numerous fields throughout the U.S.' and dating back to 1996, was analyzed and compared to offsets using conventional fluids. Selected examples from this analysis will be examined, and field data utilized to accomplish this study will also be discussed.

Application of the organo-borate crosslink mechanism in fracturing operations improves long-term production by a number of methods. More complete break profiles may be obtained with an organo-borate fluid than conventional fluids because of the chemical formulation of the crosslinker itself. This break profile contributes to better long-term fracture performance by improving conductivity nearer the fracture tip, extending the effective fracture length over conventional fluids. Consequently, the long-term production benefits are improved, as more reservoir area is available to make a contribution. The organo-borate crosslinker technology also contributes to improve fracturing dynamics, as it delivers significantly higher in-situ viscosity development than conventional fluids. This viscosity development improves fracture generation capabilities, reduces tortuosity concerns, and places proppant more effectively than conventional fluids. Organo-borate crosslinker technology also dramatically improves the temperature stability of a fracturing fluid compared to a conventional mono-borate.
A Novel Approach for Enhancing Proppant Consolidation: Laboratory Testing and Field Applications
Authors: Nguyen P. D. , Weaver J. D. , Parker M. , McCabe M. , Hoogteijling M. , van der Horst M. J.
Published: December 2007

Curable resins have been used to coat onto proppant for controlling proppant flowback after hydraulic fracturing treatments as well as in screenless, frac pack completions. As more wells are drilled into deeper reservoirs, severe conditions including high temperatures and high production flow rates impose more constraint requirements on the use of curable resin systems. This paper presents the results of an extensive study, both laboratory and field testing, of a new liquid resin coating system that is particularly useful in controlling proppant flowback in high-temperature, high-flow rate wells. Additives included in the liquid resin system eliminate fracturing fluid interference and permit good consolidation properties to be achieved without any formation closure stress.

Results of this work demonstrate the difficulty in designing fracturing treatments such that the curing of resin does not occur too fast relative to fracture treatment time and the time for formation closure to achieve good consolidation, but fast enough to prevent flowback upon fluid recovery operations. The useful window for resin-coated proppants has been greatly expanded by the incorporation of simple chemical additives into the resin that react with fracturing fluids, rendering them noninterfering to the consolidation process. These additives permit resin-coated proppant to achieve good consolidation properties without closure stress.

This study provides new answers as to why resin-precoated proppant (RCP) consolidations sometimes fail in the field. Operators can use the information presented to help them select the appropriate curable resin systems for their applications where consolidations are expected to withstand production conditions of high temperatures, high flow rates, and stress loading.
Temperature effects in Brazilian, uniaxial and triaxial compressive tests with high porosity chalk
Authors: Madland Merete Vadla , Korsnes Reidar Inge , Risnes Rasmus
Published: December 2007

The objective of the present project was to study how high temperatures affect the different mechanical parameters of chalks. Two types of high porosity outcrop chalks were used. Several series of Brazilian, uniaxial and triaxial compressive tests have been performed at both ambient and reservoir temperature, 130 °C the Ekofisk temperature. Both water and glycol were used as saturating fluids, and in addition some test series on dry chalk were included. The results so far show that the yield envelope has a tendency to shrink with increasing temperature. Both cohesion and the hydrostatic yield stress are typically reduced about 20 % in going from 20 to 130 °C, but the magnitude of this reduction may be chalk type dependent. For the friction angle there are some indications of a slight increase with increasing temperature, but some results point in the opposite direction. Experiments with dry chalk show some degree of strengthening, probably due to drying effects.
Field Application of a Novel Emulsified Scale Inhibitor System to Mitigate Calcium Carbonate Scale in a Low Temperature, Low Pressure Sandstone Reservoir in Saudi Arabia
Authors: Nasr-El-Din H. A. , Lynn J. D. , Hashem M. K. , Bitar G.
Published: December 2007

This paper describes field application of a novel scale inhibitor squeeze treatment to mitigate downhole scale (calcium carbonate) present in several oil producing wells in a sandstone reservoir in central Saudi Arabia. The sandstone reservoir is weakly consolidated, water sensitive, and sanding problems were noted in several wells. The water cut in the scaled wells ranges from 3 to 80 vol%. To avoid sanding problems, most of these wells were gravel packed. In addition, the reservoir pressure and gas oil ratio are low and, as a result, electrical submersible pumps (ESPs) are used to produce these wells. The sandstone reservoir is heterogeneous and contains up to 14 wt% clay minerals in some zones. The bottom hole temperature is nearly 160°F. A thorough investigation was undertaken to develop a suitable scale squeeze treatment to mitigate the scale, and to assess the effectiveness of the treatment in the field.

Based on extensive lab studies, a new emulsified scale inhibitor treatment was designed and applied in more than fifteen wells. These wells were descaled prior to the squeeze treatment as was detailed by Nasr-El-Din et al.1 All scale squeeze treatments were conducted using 1.75 or 2 in coiled tubing. Because the formation is water-sensitive, the main treatment, the pre and post flushes were designed to minimize formation damage due to fines migration and clay swelling. Following the treatment, the well was shut-in for two days to give ample time for various reactions to occur. Chemical analysis of well flow back samples was used to estimate the lifetime of the squeeze treatment. In addition, a downhole video camera was used to follow scale formation following the treatment.

The scale squeeze treatment was conducted in more than fifteen wells. The emulsified inhibitor was mixed in the field and was injected into the target zones without encountering any operational problems. Analysis of flowback samples indicated that the treatment did not affect well productivity or water cut in any of the treated wells. Based on field data, it is known that the treatment lifetime is greater than two years. The minimum scale inhibitor concentration, presented as phosphorus, is nearly 1 mg/L.
Getting the Best From Formation Tester Sampling
Authors: Hy-Billiot J. , Bickert J. , Montel F. , Segalini G.
Published: December 2007

Formation Testers provide valuable information on compositional gradient within a reservoir fluid column. But it has been established that fluid samples obtained with oil-based muds (OBM) are contaminated by the filtrate to an extent dependent on the "pump out" time and the original fluid properties. Except in some very specific cases, the contamination reaches a residual asymptotic level with the pump-out duration. When fluid viscosity is high, the residual contamination is high too and its impact on the physical properties can be huge.

New techniques have been developped to deal with contaminated samples. This paper describes different ways to get rid of contamination and assess the reservoir fluid composition and associated PVT properties. It then offers some recommendations for sampling procedures. A distinction is made between simple miscible cases and complex two-phase cases where the mass exchange between reservoir fluid and filtrate is no longer negligible. Three decontamination methods are presented, and the reliability of the calculated properties of the de-contaminated fluid is discussed.

Through field examples, the paper provides a methodology for dealing with contaminated samples and tips for getting the best from Formation Tester samples.

The main contributions are the methodology for decontamination of Formation Tester samples in the case of OBM drilling, and the integration of the information from this sampling tool into the reservoir fluid evaluation procedure
Prediction of Capillary Fluid Interfaces During Gas or Water Coning in Vertical Wells
Authors: Johns Russell T. , Lake Larry W. , Delliste Arnaud M.
Published: December 2007

Gas and water coning cause oil production to be significantly reduced and costs associated with the production to be significantly increased. Simulation and experimental methods, coupled with simple analytical solutions or correlations, are typically used to identify the oil rate that minimizes coning and maximizes recovery. Current analytical solutions, however, assume negligible capillary pressure, which leads to segregated flow. This paper presents new analytical solutions that relax this assumption.

The new coning solutions apply to vertical wells where in situ fluids are in vertical equilibrium. The development identifies the important dimensionless groups that control the effect of coning on oil recovery and illustrates how simultaneous two-phase flow affects capillary fluid levels in the formation. Dimensionless two-phase production windows are constructed to identify critical rates, the largest oil rate at which water (or gas) will not be produced.
A Method for Developing Rock Mechanical Property Logs using Electrofacies and Core Data
Authors: Miskimins Jennifer , Hurley Neil , Graves Ramona
Published: December 2007

A methodology for developing an extremely detailed, synthetic rock-mechanical properties log is presented. The technique uses electrofacies developed from FMI images in conjunction with rock properties measured directly from core. The analysis is performed using data from the North LaBarge Shallow Unit (NLBSU) located in the Green River basin in southwest Wyoming. The NLBSU produces from Cretaceous Mesaverde sandstone that consists of thinly bedded sand and shale layers. These laminated layers are generally less than 1.5 inches (4 cm) thick.

Hydraulic fracturing is necessary for economical production from the NLBSU wells. The thin-bedded nature, as well as the low permeability associated with the reservoir, requires this completion technique. As such, an understanding of how hydraulic fractures grow in this thin-bedded environment is essential.

Acoustic measurements taken approximately every 0.5 inches (1.3 cm) on 90 ft (27.4 m) of core provide a detailed mechanical properties log for that particular section of the well. A relationship between these properties and the conductivity readings from the FMI log is developed which allows extrapolation of the rock-mechanical properties to the uncored sections of the subject well. Extrapolation of the rock-mechanical properties to other wells in the field is also possible.1 The resolution provided by the FMI log permits a detailed rock-mechanical log to be developed for the entire well. This rock-mechanical properties log exhibits significantly more detail than similar logs developed using dipole sonic logs.

The described methodology is being used to improve hydraulic fracturing techniques in the subject field. The technique presented can be used in other fields, thus providing an aid to improving hydraulic fracturing models. Other simulation techniques that require mechanical properties, such as reservoir modeling or wellbore stability models, could also benefit from improved input data provided by this technique.
Terang/Sirasun Field Development: Geohazards Engineering
Authors: Smith N. T. G. , Jayson D. M. , Fenton C. H. , Gillies M.
Published: December 2007

The Terang, Batur, East and West Sirasun gas reservoirs are located 120 km north of Bali on the Kangean shelf of the North Bali Basin, in water depths ranging from 100 to 300 metres. The reservoirs collectively contain around 1 TCF of recoverable gas. It is proposed to jointly develop the reservoirs by means of a subsea development and associated floating production unit (FPU), with gas being exported to the nearby East Java Gas Pipeline for onward transmission to Java.

The North Bali basin lies above a major subduction zone, and is consequently an area of extensive seismic and volcanic activity. The proposed Terang/Sirasun development location is subject to numerous geohazards, including fault rupture, shallow gas, slope instability, liquefaction, and strong earthquake shaking. These geohazards pose risks to safety, the environment and the field facilities, both during construction and during production operations. Consequently, a key element of the early engineering definition phase of the project, prior to undertaking FEED, has been the analysis and quantification of the geohazard risks.

A geohazards engineering programme was undertaken during 2000 – 2001. An integrated multidisciplinary team was assembled, covering the geophysics, geology, drilling, completions, subsea and facilities disciplines. An extensive data acquisition programme was undertaken, comprising some 5,600km of 2D seismic lines, swathe bathymetry, sidescan sonar, sub-bottom profiling and geotechnical sampling. The team used state-of-the-art visualisation technology to map the hazards and plan wellbore trajectories and facility locations to minimise risk. Limit state analyses of the wells and seabed facilities were performed to determine capacity to respond to seismically triggered events. Finally, extensive probabilisitc analysis utilising decision (or logic) trees was undertaken to quantify the safety and economic consequences of geohazard events in terms of environmental impact, asset damage and production interruption.

This paper describes the geohazards engineering programme and presents lessons learned. The programme received a commendation in BP's internal Helios Awards scheme during 2001.
Oil Well Performance In The Presence Of A Gas Phase
Authors: Hassan M.
Published: December 2007

Production and pressure build-up tests conducted on several wells at different stages of reservoir depletion are examined. The objectives are two-fold; to evaluate the deterioration of well productivity during two-phase flow and, to find a procedure to estimate the single phase transmissibility from pressure build-up tests carried out in the presence of free gas saturation.

Satisfactory results are obtained when the relative permeability effect is accounted for in the following manner; the flowing period is described as a drainage process whereas the closed-in period is assumed to resemble an imbibition behaviour. In addition, the portion of the well drainage area in which gas saturation is below the critical value is assumed to have a constant effective permeability to oil. The last assumption is supported by actual well performance.

Introduction

The flowing and shut-in performance of oil wells producing from a multiphase, oil-gas, system has been investigated. This work has been based on data acquired from production and pressure build-up tests performed on wells producing from the Bu Hasa Shuaiba reservoir situated on-shore in Abu Dhabi in the United Arab Emirates. The field is presently operated by Abu Dhabi Company for Onshore Oil Operations.

The reservoir was brought on stream in 1965 and produced by fluid expansion for about seven years before a peripheral water flood was initiated to arrest the rapid decline in reservoir pressure. At the reservoir crest the pressure fill to a level of about 100 psi above the local saturation pressure and some of the crestal wells were flowing at a bottom hole pressure 700 psi below the bubble pressure 700 psi below the bubble point. Under such conditions severe point. Under such conditions severe deterioration in the productivity index was observed but well productivity was recovered after several productivity was recovered after several months of either shutting-in the well or beaning back the production so that the bottom hole flowing pressure remained above the saturation pressure.

The objective of this study was to identify a procedure to predict the inflow performance below the bubble point and to evaluate the point and to evaluate the permeability to oil as a single phase from permeability to oil as a single phase from pressure build-up tests performed in pressure build-up tests performed in the presence of free gas saturation.

Horizontal radial flow and homogeneous reservoir rock characteristics have been considered. The porosity, permeability and irreducible water permeability and irreducible water saturation were assumed to remain constant with depletion.

FIELD RESULTS

Flowing Well Performance

Producing rates and bottom hole pressure measurements have been pressure measurements have been closely monitored throughout the history of the wells considered here.
Geopressure Detection Using Reflection Seismic Data and Rock Physics Principles: Methodology and Case Histories From Deepwater Tertiary Clastics Basins
Authors: Dutta Nader C.
Published: December 2007

Subsurface formations with pore fluid pressure in excess of the hydrostatic pressure (geopressure) are encountered worldwide. Although there are a multitude of causes that can result in geopressure, under compaction due to rapid burial of sediments is the predominant cause of geopressure. Typically, if the loading process is rapid, fluid expulsion through compaction is severely retarded, especially in fine-grained sediments with low permeability such as silts or clays. This results in stress redistribution within the column -a greater proportion of the overlying weight of the sediments is borne by the fluids than when the sediments compact normally, causing a decrease in the stress acting on the rock framework. Dehydrating bound water from clays within shales further complicates this phenomenon as compaction proceeds with the depth of burial with increase in temperature.

Geopressured formations pose significant threats to drilling safety, and the cost of mitigation, especially, in deepwater settings, is high…to the tune of $1.08 billion per year world-wide. Proper planning before drilling is key to lowering costs and increasing safety. In this regard, the role of seismic is of paramount importance. Seismic wave attributes (amplitude, velocity, coherency, etc.) are affected when stresses acting on the sedimentary column (effective or differential stress) are low. These attributes can be analyzed to obtain signatures, or lack of fluid transport over the geologic time- both qualitatively and quantitatively. Using the seismic, zones of trapped fluids and pressured compartments can also be mapped prior to drilling. With either an analogue or a reliable low-frequency velocity model, it is also possible to map fluid transport effects in the reservoir scale using seismic inversion techniques.

In this paper, we illustrate how this process works using seismic data at various scales, from the low frequency reflection seismic at exploration frequency scales to those employed at well-logging scales. A rock-model-based approach especially suited for deepwater pore pressure imaging is introduced. It includes the effect of shale burial diagenesis, and uses the velocities derived from inversion of prestack seismic data. The procedure yields details of pre-drill pore pressure images with significant clarity as well as pressure versus depth profiles appropriate for drilling applications. In particular, prestack full waveform inversion yields Poisson's ratios that are useful not only for pressure and fracture gradient estimations but also for lithology and fluid identification. This technique is also applicable to identification of shallow water flow formations that pose drilling hazards in deep water. The procedure is illustrated with examples from several deepwater basins.
Application of Multilateral Technology in Drilling an Offshore Well, Indonesia
Authors: Tanjung Erwindo , Saridjo R. , Provance Stan M. , Brown Pat , O'Rourke Tim
Published: December 2007

This paper presents the case study of the implementation of multilateral technology for Repsol-YPF Maxus in East Rama field, Southeast Sumatra concession, Indonesia. Repsol-YPF wanted to introduce multilateral technology in an attempt to reduce overall cost related to drilling, production and facilities; as well as increase slot availability on its offshore platforms. Drilling two successful pilot wells with the BIMA Multi Purpose Service Vessel (MPSV) in August of 2001 initiated the project. One pilot well, East Rama AC-6P, was drilled vertically and the other pilot, East Rama AC-7P, drilled directionally by sidetracking from the East Rama AC-6P surface casing. These pilot wells successfully discovered two hydrocarbon bearing pay sands in the Talang Akar formation. Based on this success the East Rama field had a need to drill additional producing wells. With the slot limitation on the platform (i.e. one available slot coupled with the desire to achieve optimal reservoir recovery), multilateral technology was selected. The use of this technology was not just to prove its' viability for well construction resulting in future savings of field development projects, but also to calculate and compare two single well costs to one multilateral. This paper categorizes the reasons for choosing multilateral well as the development option, planning and preparation of the well, and all results of the operations. Issues covered include strategic well design, economic analysis, and the problems encountered during drilling operation. The lessons learned are documented and presented as a reference for future developments, specifically for multilateral technology and generally for drilling improvement.
Application of Neural Network to the Determination of Well-Test Interpretation Model for Horizontal Wells
Authors: Sultan Mir Asif , Al-Kaabi Abdulaziz U.
Published: December 2007

Well-test model identification and, subsequently, model parameters determination are more complex in horizontal wells than in vertical wells. This is due to the increase in number of flow regimes occurring during a flow period and the fact that strong correlation exists between model parameters.

This study presents a new approach for automatic model identification and computer-aided well-test interpretation in horizontal wells. The new approach is based on using neural network to (1) identify the well-test interpretation model; (2) identify flow regimes; and (3) mark the position of identified flow regions on the derivative plot of well test data.

This work consists of first generating common model signatures using Ozkan and Ragavan analytical solutions for horizontal wells in various reservoir and inner boundary conditions assuming laterally boundless reservoirs. Next, these signatures are used to train neural networks for three identification stages; model identification, flow regime identification, and position of flow regime identification. Separate networks were trained, then tested and validated using synthetic as well as field data. Once the three identification stages are completed, specialized plots for data points falling into each flow regime are used to determine initial model parameters. Final model parameters are determined using nonlinear regression.

A comparative study was carried out using different network architectures. Modular approach with direct data utilization is found to be most suitable for implementation of our approach.
Effect Of Well Locations On The Performance Of A Multilayered Reservoir
Authors: Abed A.F. , Hadidi A.M.
Published: December 2007

Well location is only one variable of several variables that affect the performance of a multilayered reservoir. performance of a multilayered reservoir. In order to optimize development as well as production plans pertinent to any reservoir it is a good oil field practice to study all these dependent variables of the recovery factor function. In this paper the study of well location variable paper the study of well location variable will be only presented.

A series of reservoir model studies using detailed grid configurations was performed to study the effect of well performed to study the effect of well locations on the performance of different layers in a reservoir of large gas cap and relatively thick oil column and producing under pressure maintenance.

The results showed that, keeping all other dependent variables relatively constant, the well locations have a considerable effect on the performance of different layers. Vertical sweep efficiencies in one case were seen to vary from 25% to 32% of the initial oil-in-place at the end of the same prediction period. The studies also showed that the sweep efficiency increases with increasing distance between the producers and injectors.

Introduction

Recovery of hydrocarbon reserves is a function of several variables which are connected by one or more relations. The reservoir engineering variables of the recovery function are areal sweep, vertical sweep and microscopic displacement efficiencies. Each one efficiency is a function of several variables. It is very difficult, if not impossible, to optimize analytically the recovery function because of the implicitness of the relations connecting different variables. However, the recovery function can be optimized numerically using reservoir simulation models.

For a function of several variables it is very important to define the variables and their interrelation. For example all rock and fluid properties are functions of pressure and temperature levels. Well pressure and temperature levels. Well location is only one variable of several variables that influence the performance of a reservoir by affecting the areal and vertical sweep efficiencies.

This paper describes the effect of well locations on the performance of a multilayered reservoir.