bluuebunny/crossref_metadata_2025 huggingface dataset:
The Fault Block Model: A Novel Approach for Faulted Gas Reservoirs
Authors: Ursin J- R. , Mørkeseth P. O.
Published: December 2007

The Fault Block Model was designed for the devel-opment of gas production from Sleipner Vest. The reservoir consists of marginal marine sandstone of Hugine Formation. The structure is dome shaped and highly faulted with good reservoir productivity. Based on geological interpretation, location and extent of faulting in the reservoir was carried out and the effect of faulting as flow barrier was evaluated. Internal cross-flow communications between adjacent fault blocks defined by throw of faults were established.

The model redefines individual fault block traps in terms of block volume and cross-flow probability to adjacent blocks and estimates the number and lo-cation of wells required for optimum recovery of the gas reserves. The model predicts the corresponding well coverage, from which production profiles are calculated.

Modelling of highly faulted and compartmentalized reservoirs is severely impeded by the nature and extent of known and undetected faults and, in particular, their effectiveness as flow barrier. The model presented is efficient and superior to other models, for highly faulted reservoir, i.e. grid based simulators, because it minimizes the effect of major undetected faults and geological uncertainties. The geological interpretation and its uncertainty is minimized using fault block volume and cross-flow probability, which subsequently may translate into gas production profiles. The geological uncertainties are carried through in the model by error propagation techniques.

In this article we present the Fault Block Model as a new tool to better understand the implications of geological uncertainty in faulted gas reservoirs with good productivity, with respect to uncertainty in well coverage and optimum gas recovery.
Meeting the Challenges of Deepwater Gulf of Mexico Drilling With Non-Petroleum Ester-Based Drilling Fluids
Authors: Carlson Tom , Hemphill Terry
Published: December 2007

The search for recoverable hydrocarbons in the Gulf of Mexico has moved into increasingly deeper waters. Since its introduction in the Gulf of Mexico in 1993, the ester-based drilling fluid system has been used on five deepwater wells. This paper describes the applications of the ester-based system and its ability to handle the special challenges of deepwater drilling in the Gulf of Mexico.
The Generation of Grid Block Permeabilities from Core Data
Authors: Yang Y. S. , Thompson C. J. , McCarthy J. F.
Published: December 2007

The grid blocks used in reservoir simulations typically have dimensions in the order of tens or hundreds of metres, whereas the core data which are used to generate the grid block permeabilities have a scale of only a few centimetres. Thus it is necessary to scale up the data over several orders of magnitude to derive the "effective" permeability distribution at the grid block scale. This is commonly done by taking standard measures of the mean of the data (e.g. arithmetic, geometric or harmonic mean) and making ad hoc assumptions about the rescaled variance. Such an approach can lead to costly errors. However, the obvious alternative — to iteratively scale up from the core to the grid block scale via detailed flow simulations — is often not feasible due to computational limitations. This problem has been resolved in recent years by the development of fast and accurate algorithms for computing the effective permeability of large systems, containing up to millions of grid blocks.

This paper describes a computationally efficient software package which has been developed to generate grid block permeabilities for reservoir simulations from core data. Upscaling is performed using algorithms based on random walks and real-space renormalization group methods. Geological correlations and anisotropy at the core scale can be incorporated using geostatistical techniques (e.g., sequential gaussian simulation). The paper emphasises a practical application of the software to field data.
Thermometric Well Testing on the Vietnam Offshore
Authors: San T. N. , Shtyrlin V. F. , Vakhitov G. G. , Loi L. M. , Listengarten Leonid , Hien D. L.
Published: December 2007

It is impossible to control and adjust an oil and gas field development without determining the flow intervals of production wells. For that it is preferable to get production profiles by using the downhole flowmeter. There are, however, some main restrictions for wide-spread application of them on the offshore of Vietnam as follows: –The flowmeter spinner velocity cannot indicate correctly in the open hole wells having a ununiform diameter.–It is unable to carry out in the case when the tubing shoe is lower than top formation on 300 - 500m.

In this paper, the authors present a summary of temperature profile method to determine the flowing and intaking intervals of wells drilled in basement of the White Tiger Field on Vietnam offshore.

For last 2 years more than 30 wells were surveyed by this method in the above mentioned conditions.

This paper presents the theory and practic of well temperature profile surveys, the concrete examples of data interpretation using the software "Oiltest".
Project Rulison and the Economic Potential of Nuclear Gas Stimulation
Authors: Coffer H.F. , Frank G.W. , Bray B.G.
Published: December 2007

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Project Rulison was designed to use underground nuclear technology to determine the potential of this technique for commercial development of the Mesa-verde formation of the Rulison Field in Garfield County, Colorado. A method of stimulation, far greater in magnitude and efficiency than conventional hydraulic fracturing, is needed to recover the gas at economic rates.

Detailed testing of the Project Rulison exploratory well, R-EX, provided data on geology, hydrology and provided data on geology, hydrology and reservoir characteristics. The data obtained from the testing have been used to determine the flow capacity of the Mesaverde reservoir. The reservoir characteristics were then used as input data to make predictions of post-shot reservoir performance in the nuclear stimulated well, using a radial, unsteady state gas flow computer model. The calculations show that rates of production will be sufficient if costs production will be sufficient if costs can be controlled. Costs of nuclear stimulation must be drastically reduced for a commercial process. The total Project Rulison cost will be approximately $5.9 million. At such prices, nothing can possibly be prices, nothing can possibly be commercial; however, as outlined in the paper, these costs can come down in a paper, these costs can come down in a logical step-wise fashion to an economic number.

A nuclear explosive with a design yield of 40 kilotons was emplaced and detonated in a 10-3/4" casing at a depth of 8426' below ground surface and detonated on September 10, 1969. A preliminary appraisal of the data taken at shot time indicate that the explosive behaved as predicted. The explosion was completely contained underground as predicted and no major seismic damage occurred. The post-shot reentry program, in the spring of 1970, will include reservoir testing to determine the degree of stimulation achieved.

Introduction

The greatest challenge to the oil industry has always been how to make available oil and gas at an economic rate. The increasing costs of exploration and the impending shortage of natural gas have made the economic development of marginal resources not only attractive, but necessary.
Prediction of Critical Condition for Fines Migration in Petroleum Reservoirs
Authors: Rahman S. S. , Arshad Aziz , Chen Hong
Published: December 2007

Formation damage due to fines migration is a threshold type process in that there exists a critical condition at which a petroleum reservoir is susceptible to formation damage. This paper presents a physical model for predicting the critical condition for particle deposition based on experimental data and trajectory analysis. Suspensions (bentonite, kaolinite) were passed through a capillary (100 fim) at a controlled flow rate and at the same time, pressure drop across the capillary was monitored. Based on the log jam effect a criterion is proposed to predict the critical condition for particle deposition in porous media.
Management of Critical Equipment (Wellhead Systems)
Authors: Barry A. G.
Published: December 2007

Precise documentation is a key dement in the management and control of critical equipment, Having correct and easily accessible information for equipment which in some cases is in excess of 20 years old has saved Esso Australia Ltd thousands of dollars in engineering time and has reduced rig downtime.

Safety and the Environment are of prime importance in Esso operations and the management of critical equipment is instrumental in achieving objectives for these areas.

Esso has completed an extensive program to document and control critical wellhead equipment and this has involved: Surveying and documenting the 300 existing wellheads offshore;Increased emphasis on material specification and control;Reviewing and implementing new techriology;Increased control over wellhead equipment refurbishment; andIncreased emphasis on offshore wellhead maintenance.

Benefits experienced by Esso after increasing the focus on critical equipment management include increased safety, increased confidence in equipment, decreased engineering time, and decreased rig downtime related to incorrect or incomplete information.
Enhanced Statistical Variation Method For Determining Zone Isolation In Complex Cements
Authors: Graham W. L. , Harness P. E. , Griffith J. E. , Lee S. , Miller J. , Maloney B. J.
Published: December 2007

Complex, or non-standard, cement slurries create special, difficult cement evaluation problems which are magnified when high density drilling fluids are used. These complex slurries include lightweight cements (water-extended, ceramic bead, and nitrified cements), gas-channeled cements, multistage density cements, as well as intervals of cement that are contaminated with drilling fluid. Current cement evaluation methods, via conventional logging techniques, are based on signal amplitude, acoustic impedance, and compressive strength relationships. These properties are derived from the materials behind the pipe and interpretation methods rely on how these properties differ in fluids versus standard cement. This desired contrast is not always evident in complex cements; however, statistical variance techniques have been developed that permit accurate interpretations of zone isolation in low-density cements.

This new approach to determining zone isolation in lightweight and complex cements with ultrasonic cement evaluation tools is called Statistical Variation Plot (SVP) and is based on the following two factors: Distinguishing solid materials from fluids in the casing-borehole annulusAssuming that solid material cannot be displaced during the remedial cementing operation whereas fluids may be displaced1

It will be shown that this technique is superior to conventional evaluation techniques when the acoustic properties of the cement are similar to the acoustic properties of the annular fluid.
New Cement Additive Improves Slurry Properties and Saves Cost
Authors: Pollard Robert , Hibbeler Jeff , Dilullo Gino , Shotton E. A.
Published: December 2007

A new cement additive has been developed which improves slurry performance and reduces cost. The additive is a vitrified aggregate of calcium-magnesium aluminosilicates with potential cementitious reactivity, hereafter abbreviated CMAS. CMAS has been used successfully on oil and gas wells throughout Indonesia.

The purpose of this paper is to illustrate the technical enhancements and cost effectiveness of slurries incorporating CMAS. Laboratory data is presented and working mechanisms are defined to highlight CMAS's positive effect on; compressive strength, fluid loss control, free water control, gas migration control, resistance to strength retrogression and aggressive fluids. Finally, case studies and an economic analysis are presented to show the cost savings for actual well applications.
Drilling a High-Angle Exploration Sidetrack Downdip Along Bedding, Gobe Main Prospect, Papua New Guinea
Authors: Jordan J. A. , Valenti G. L.
Published: December 2007

The Gobe 4X sidetrack exploration well was drilled in a remote area of the Southern Highlands Province of Papua New Guinea using an innovative sidetrack technique for delineating hydrocarbons. After gas was encountered in the Gobe 4X straight hole, a non-conventional sidetrack was drilled down dip along the bedding plane of the reservoir sand and determined the gas-oil contact and the oil-water contact with a single wellbore thereby establishing the limits of the oil band. This was accomplished despite a difficult well trajectory, high deviation angle, large stepout and limited structural information.
The Application of In-Situ Stress Measurement and Numerical Stress Analysis to Coalbed Methane Exploration in Australia
Authors: Enever J. R. , Bocking M. A. , Clark I. H.
Published: December 2007

Exploration for coalbed methane in Australia has evolved over the past few years to a point where the focus is very largely on the targeting of regions of relatively higher permeability. Gas content has generally been found to be adequate enough to encourage commercial development. Permeability has, however, often been found to be too low by comparison with overseas experience to suggest commercially viable gas production rates.

The unravelling of an understanding of coal permeability and its relationship to the geological environment is being helped by the application of in- situ stress measurement (conducted in coal and associated sediments) and numerical stress aiialysis. Knowledge of the in-situ stress field becomes a means by which to quantify the relationship between coal permeability and the related structural geological framework, leading ultimately to a better basis to guide the development of exploration strategies.

This paper describes the results of in-situ stress measurements conducted in a number of coalbed methane exploration holes in the Sydney Basin and associated stress analyses conducted to examine the influence of in-situ stress and geological structure on coal seam permeability as measured by well test.
PNG's Kutubu Project: Lessons in the First 100 Million Barrels
Authors: Magner T. N. , McKay W. I.
Published: December 2007

The Kutubu Project was approved for development in December 1990. Since that time twenty-four new development wells have been drilled, field facilities and export systems were successfully completed and commissioned, and some 85 million barrels of light, sweet Kutubu crude oil have been produced and exported (through July 1994). At present, the field produces approximately 120,000 BOPD from 27 vertical wells and two horizontal wells. Reservoir pressure maintenance is provided by gravity-stable re-injection of produced gas into 5 wells. By November 1994, cumulative production should be in excess of 100MMSTB.

In spite of all the of the studies and analyses conducted since the initial oil discovery in 1986, considerable uncertainty existed over the expected performance of the Kutubu reservoirs prior to initial production. On the whole, the reservoirs have met or exceeded expectations to date. This is in part due the effective planning and implementation of a strategy to manage the Kutubu reservoirs. This reservoir management strategy combines an aggressive program of reservoir surveillance, data collection, computer simulation and continuous reassessment of previous assumptions.
Alternatives to Proprietary Systems for Safety and Production Automation
Authors: Olszewski Keith , Godfrey C. W. , Perkins D. H. , Plunkett Joe
Published: December 2007

In the prevailing economic climate of the oil and gas industry, operators must increase efforts to seek greater operational efficiency. They must also consider the more stringent regulatory requirements that are in place today for protection of personnel, equipment, and the environment. Implementation of a safety and production automation system for a producing field or battery can support both needs by optimizing production and reducing maintenance needs as well as facilitating compliance to safety requirements for personnel and the environment. If the installation embodies an "open system" philosophy, operational changes that may later require system redesign can be addressed more easily than with other proprietary systems and will involve lower maintenance costs.
Pressure Relieving System Design and Evaluation
Authors: Kenez J. D.
Published: December 2007

The pressure relief system in a hydrocarbon processing plant is essential to its safe operation. In order to design pressure relief systems for a new plant or to evaluate existing systems, a systematic method should be employed taking into account the governing codes, industry recommended practices and the operating company's standards.

This paper describes a design procedure based on the preparation of a project specific overpressure design philosophy, which incorporates the designer's interpretation of the codes, recommended practices and standards.

All credible causes of equipment overpressure are then identified and required relieving rates quantified using simplified calculation methods and process simulation for fluid properties. The resultant information is stored in a data base and is then used to design the relief disposal system including relief valves, relief headers and knockout drums. Proprietary software is used for the sizing of relief system piping.

This design procedure, which can be equally well applied to the review of existing facilities, results in a sound plant relief design as well as providing auditable design documentation suitable for the maintenance of ongoing plant records.
Development and Trial of Microwave Techniques for Measurement of Multiphase Flow of Oil, Water and Gas
Authors: Ashton S. L. , Cutmore N. G. , Roach G. J. , Watt J. S. , Zastawny H. W. , McEwan A. J.
Published: December 2007

A prototype microwave and gamma-ray MFM has been developed for measurement of oil, water and gas flowrates on production pipelines and has been successfully trialed at the Thevenard Island oil production facility. The microwave and gamma-ray MFM determined the oil and water flow rates with errors of 5.4 and 5.9% relative respectively for the wide range of wells and flow conditions during the trial period. A prototype non-intrusive microwave MFM is being developed for measurement of oil, water and gas flow rates on production pipelines. The microwave MFM will be trialed on the West Kingfish platform in Bass Strait in late 1994.
The Use of Blast Furnace Slag in North Sea Cementing Applications
Authors: Saasen Arild , Salmelid Bjarne , Blomberg Nils , Hansen Karsten , Young S. P. , Justnes Harald
Published: December 2007

This paper discusses further the application of Blast Furnace Slag (BFS) in the cementing of oil and gas wells, with particular emphasis being placed on the suitability of BFS for offshore operations in the North Sea. The paper outlines the chemical reactions which occur during curing of BFS and discusses effects of different BFS sources and testing requirements. The application of BFS as a drilling fluid additive to improve cement bonding by solidification of the filter cake is discussed with respect to the effects of BFS on drilling fluid rheology and fluid loss. BFS is found suitable for low volume operations such as plug cementing, however wider use BFS is seen to be limited by logistics and occupational safety aspects for offshore North Sea applications. The environmental benefits to be gained by use of BFS is limited.
A New Correlation for Sedimentation of Concentrated Suspensions in Shear-Thinning Fluids
Authors: Allen Elise
Published: December 2007

An experimental investigation has been made of the settling behaviour of concentrated suspensions in viscoelastic polymer solutions, as a function of the fluid rheological properties. The sedimentation experiments examined a wide range of shear-thinning and viscoelastic behaviour (power-law index n range 0.2 -1.0 and relaxation time X range 0.1 -100 sec), using model suspensions of closely-sized glass beads. The experimental results were compared with four available theoretical models which are based on the fluid rheological properties. A new relationship is proposed, based on the single particle settling velocity, a critical solids volume fraction c* and the fluid rheological properties. The new relationship predicts two different settling regimes: fast-setting for low solids loading c ≤ c*, and slow-settling for high solids loading c ≥ c*. The new relationship simplifies to the well- established Richardson-Zaki correlation for sedimentation in Newtonian fluids.
Biologically Controlled Water Diversion Demonstrated by New Visual Experimental Technique
Authors: Paulsen J. E. , Oppen Eirik , Vatland Arild , Hanssen J. E.
Published: December 2007

A microbial enhanced oil recovery (MEOR) technology for optimisation of waterflood sweep efficiency was studied using a transparent pore micro model and a recently developed cybernetic image processing method (Automated Microscope Observation Reaction System = AMORS). Indigenous seawater microbes were stimulated with a nutrient package and allowed to develop inside the once through flow cell; a replica of the pore structure of a North Sea sandstone reservoir.

Microbial growth, as a result of subsequent controlled addition of nutrient and minerals, was observed in the automated microscope observation /reaction system. This novel integrated software/hardware cybernetic design allows approximated real-time, essentially simultaneous observation of several critical sites in the network and facilitates selective recording and compilation of observations as a function of the biological activity at each particular site. Local in-pore flow velocity measurement was possible to carry out by measuring the velocity of the particulate matter in pores/pore throats of different sizes. Sensitive, automated monitoring of the micro model pressure gave additional information of the degree of blockage.

Attachment of bacteria and development of bio mass, slime and extra cellular polymeric material was found to be most pronounced in channels of preferential water flow. The growth and subsequent narrowing of the pore network was not following a homogenous pattern, The possibility of predicting the blocking phenomenon as a function of growth rate of bacteria and/or concentration of nutrients (flow rate) is discussed with reference to the data collected with the AMORS system.

The use of micro models fitted with the AMORS package is an important step in revealing the nature of microbial blocking phenomena in porous matrices. Reservoir potential evaluation and consideration of MEOR process logistics, as compared to alternative treatment methods indicates that selective biological diversion may be a highly cost-effective and controllable way of optimising waterflood sweep efficiency in many North Sea reservoirs.

AMORS is a flexible tool recommended for investigating processes that take place on a micro/macro scale.
SAG Injection in a North Sea Stratified Reservoir: Flow Experiment and Simulation
Authors: Hanssen J. E. , Surguchev L. M. , Svorstøl Idar
Published: December 2007

This paper is a study of a novel recovery process for stratified reservoirs with large permeability contrasts. A slug of foaming surfactant is injected alternately with gas, thus by analogy with WAG making this a SAG injection process. A combined ex-perimental and numerical evaluation demonstrating effective diversion by foam and significant recovery potential over WAG of the method is reported.

An experiment with the new process was performed in a visual 2-D porous medium flow model approximately scaled to the conditions of a North Sea reservoir that is characterized by high permeability contrast and limited interlayer communication. The experiment showed poor performance of conventional WAG, which swept mainly the high-permeable layer. Placement of a surfactant slug and later foam generation in the swept layer was successfully demonstrated and gave efficient injectant diversion into the other layers, resulting in complete sweep of the reservoir model by continued WAG.

History matching of the experiment was performed using a reservoir simulator in-corporating an empirical foam model and a reservoir description corresponding to the three layers of the physical model. Successful matching was obtained of WAG injection before and after foam treatment and the simulator captured the characteristic features of the foam process, including surfactant slug placement, foam generation, and injectant diversion. It was also found to allow some flexibility in process modelling by means of the available model parameters, primarily those for surfactant transport and loss, foam mobility reduction, and relative permeabilities.

In summary the results of this paper show experimentally and by simulation on the same system that SAG injection as implemented here is superior to WAG injection and that the rich observations made in the experiment can be matched with reasonable accuracy using a commercial simulator with only empirical parameters.
Developing the North Morecambe Gas Field
Authors: Rosenberg R. H. , Lane D. J.
Published: December 2007

The North Morecambe gas field due to be brought on stream in October this year is characterised by a shallow reservoir and a potentially corrosive gas composition. In the past developing such reserves would have involved extensive offshore facilities to allow drilling to achieve the required bottom hole locations and to process the gas for transportation to shore, including offshore separation and dehydration.

The paper discusses the advances in technology which allowed the development to proceed on the basis of a single not normally manned platform with all processing taldng place onshore.

It also covers the optimisation of the onshore processing facilities and the more interesting features of the pipelines and discusses the impact on the development, both onshore and offshore, of changes in environmental and safety legislation which have taken place in recent years.

The terminal is the largest gas reception facility in the UK, incorporating both carbon dioxide and nitrogen removal plants.

The project schedule was very demanding and this influenced the design both of the platform and the terminal. The challenges brought on by the constrained schedule and the solutions adopted are also dealt with in the paper.
Application of a Scale Inhibitor Squeeze Model to Improve Field Squeeze Treatment Design
Authors: Sorbie K. S. , Yuan MingDong , Jordan M. M.
Published: December 2007

The most common remedy which is applied to solve mineral scaling problems in water producing North Sea fields is the scale inhibitor "squeeze" process. The central objective of this treatment is to maintain a sufficiently high level (typically, 2-50 ppm) of inhibitor in the produced water to prevent scale formation. The process is often applied in an empirical way although a body of knowledge now exists which allows us to design this process in a more rational engineering manner. This paper presents the results from an experimental and modelling study which aimed to improve downhole scale inhibitor squeeze treatment design by extending the squeeze lifetime in the Alwyn North field.

The model used in this work is a radial single well model for describing scale inhibitor squeeze processes in the near-well formation. In order to carry out the optimisation of the squeeze design, scale inhibitor laboratory core floods were carried out at reservoir conditions in order to derive inhibitor dynamic adsorption isotherms. The model then used the isotherms to perform the prediction of the lifetimes of the multiple scale inhibitor squeeze treatments and to optimise the squeeze operational design. The improved design was then implemented in the Alwyn North field and extended squeeze lifetimes have been achieved in broad agreement with predictions.

The model correctly reproduces the effect of (i) the residual inhibitor left in the formation from the previous squeeze treatment on the lifetime of the subsequent treatment and (ii) the effect of the operational parameters, such as overflush volume, on the squeeze lifetime. Using the first squeeze treatment in the well as the base case, a modified squeeze design (in this case, a larger overflush volume) was recommended based on the model prediction. This recommended design for the inhibitor treatments was implemented in the field by the operator and significantly improved squeeze lifetimes have been achieved.

The approach for squeeze optimisation described in this paper is referred to as the development of a "Field Squeeze Strategy". This, in contrast to the "rule of thumb" empirical approach, offers a systematic and quantitative method to evaluate and improve a scale inhibitor downhole squeeze treatment. In addition, this paper also addresses the issue of how fast the formation, where it is cooled by the injected squeeze fluids, would be warmed up during a well shut-in. We intend our findings on this matter to clear up some misconceptions on local formation cooling.
Low-Pressure Gas Field Operations in Leman
Authors: Dyck W. C. , Moore R. M.
Published: December 2007

Shell U.K. Exploration and Production, operator in the U.K. sector of the Southern North Sea on behalf of Shell and Esso, has developed Block 49/26 of the Leman field, located at the southern end of the Sole Pit Basin. Gas production from Leman commenced in 1968, built to plateau level by 1971 and began declining in 1982. The field produces under natural depletion and reservoir pressure has declined from 3022 psia to 300 psia in central areas of the field. Maintaining field revenue above operating expenditure is the key to maximising recovery. The challenge of accessing the economic reserves from Leman has been tackled by maximising deliverability from the existing low rate producers, minimising operating expenditure and pursuing opportunities for productive infill drilling.

The capacity of existing wells is optimised by maximising drawdown on the reservoir. This is achieved through ongoing facility rationalisation and the tailoring of operating practices to manage the phenomena of liquid hold up and salt deposition associated with operating at low pressures. Novel completion technology has been developed to optimise the lifting of liquids from wells.

The planned rationalisation of the field's compression facilities and the conversion of six of the seven production platforms to not normally manned status will reduce operating expenditure by a third and ensure retention of high sales gas availability. In order to reduce the installations operational visit frequency, novel completion technology has been developed to provide downhole control of proppant back-production which currently occurs from some fracture stimulated wells.

The successful performance of a horizontal well in a poorly drained area of the field has opened the way for infill drilling opportunities and possible development of the low relief flank areas of the field. Future appraisal and development drilling requirements will be better defined following full interpretation of the recently acquired 3-D seismic survey.
Fully Coupled Analysis of Reservoir Compaction and Subsidence
Authors: Gutierrez Marte , Hansteen Harald
Published: December 2007

This paper discusses the differences between fully-coupled and uncoupled formulations of models of production and subsidence. For highly compacting hydrocarbon reservoirs, production can cause com-paction of the reservoir and subsidence of the over-burden, and in turn, compaction and subsidence can affect the productivity of the reservoir by increasing the reservoir pressure (i.e., the so-called compaction drive). Intuitively, analyses of production and subsidence should be done in a fully-coupled fashion. However, most, if not all, of the analyses done so far on compacting reservoirs are uncoupled where production and subsidence are calculated in a staggered manner.

The results of the numerical analyses using an uncoupled reservoir simulation, and a fully-coupled finite element simulation based on Biot's formulation (both coupled and uncoupled simulations are based on single phase fluid) of a typical compacting reservoir are presented and compared. Different pore pressure response were obtained depending on whether an uncoupled or a fully-coupled analysis was performed, and also depending on whether there is arching of the overburden or not. The results of fully-coupled analyses of compaction and subsidence showed that the generation of additional pore pressure due to compaction cannot be correctly analyzed by simply adjusting the rock compressibilities in reservoir simulation. The most pronounced effect of coupling, obtained from the numerical simulations, is on the possibility of pore pressure increase close to the reservoir flanks even during production. The implications of the differences in the results of fully-coupled and uncoupled simulations are discussed.
A Mathematical Model of Microbial Enhanced Oil Recovery (MEOR) Method for Mixed Type Rock
Authors: Sitnikov A. A. , Eremin N. A. , Ibattulin R. R.
Published: December 2007

Abstract1

This paper deals with the microbial enhanced oil recovery method. It covers: Mechanism of microbial influence on the reservoir was analysed;The main groups of metabolites affected by the hydrodynamic characteristics of the reservoir were determined;The criterions of use of microbial influence method on the reservoir are defined.

The mathematical model of microbial influence on the reservoir was made on this basis. The injection of molasse water solution with Clostridium bacteries into the mixed type of rock was used in this model. And the results of calculations were compared with experimental data.
Record Horizontal Wells for Deep Gas Reservoir Improve Productivity and Recovery
Authors: Graute Johannes , Eide Egil , Wenninger Guenther
Published: December 2007

In 1993 BEB drilled two of the world’s deepest horizontal gas wells in the Zechstein and Rotliegend formations in northern Germany. The aim of the drilling projects was to increase profitability by achieving high production rates. By minimizing the number of production wells and usage of cluster locations, a reduction of field investment and operating costs should be attained.

To achieve the objectives, the projects were planned in a multidisciplinary team. Based on reservoir descriptions, derived from 3D seismic various sensitivity runs were performed. The aim of the runs being to assess vertical permeability distribution and horizontal hole length. The application of advanced drilling and completion techniques resulted in an optimized well design from an economic point of view.

Results of both wells proved that horizontal drilling into these deep reservoirs is technically feasible and economically attractive. A comparison of vertical drilling with horizontal drilling results in a 2 to 3 fold increase in the initial producktion rates with only a 1.3 to 1.4 times cost increase. Because of the promising results of the horizontal drilling programme in 1993 a further seven new deep horizontal and two re-entry wells were drilled in 1994. In future, BEB’s standard well design will be horizontal.
Modeling of a Large Gas-Capped Reservoir With Areal and Vertical Variation in Composition
Authors: Hamoodi A. N. , Abed A. F. , Grabenstetter Jim
Published: December 2007

Compositional modeling of one of the giant middle east reservoirs overlain by a primary gas cap is presented. The reservoir is 43 Km long and 23 Km wide and is noted for its large variation in composition in the areal extent. The H2S content varies from above 10 mole % in the North to less than 1% in the South.

Current technology in compositional reservoir simulators accounts for vertical variation in composition; however the problem presented for this reservoir includes significant areal variation in composition. This paper presents a successful attempt in addressing this challenge.

Reservoir Fluid sampling included 11 bottom hole and 5 recombined surface oil samples. 10 samples are considered representative of the virgin reservoir oil. Experimental data available include extended true boiling point analysis up to C20+ of two samples, constant composition expansion, differential liberation and oil viscosity measurements. One gas cap sample was recently collected. The sample experimental data include analysis up to C20+, constant composition expansion and constant volume depletion measurements. Additional experimental data available include a swelling test and two slim tube displacement tests.

An equation of state model, capable of accurately predicting the wide range of experimental data available, spanning the full compositional spectrum of the reservoir fluid, was developed. The methodology adopted in the development and validation of the equation of state characterization is presented.

An isobar map of the saturation pressure and areal compositional distribution maps based on reservoir fluid analysis were constructed and assumed representative of the mid-reservoir depth of the most productive layer. By applying the saturation pressure versus depth gradient, base saturation pressure maps for all reservoir layers were derived.

The compositional variation was correlated against mid-reservoir depth and saturation pressure. The total reservoir compositional distribution was then determined based on the average gradient of composition versus saturation pressure, and base saturation pressure and compositional distribution maps.

The model was successfully initialized in non-equilibrium mode by defining the composition for each grid block. Stability of the model was verified, and the calculated saturation pressure distribution per layer was validated against the established distribution based on collected samples and the saturation pressure versus depth correlation. Original in-place fluid volumes were compared to black-oil model initialization data, including the original oil in place, solution gas in place and free gas volumes.

The model size is 39,780 grid blocks, 7 components and includes 400 wells. The memory requirement is 380 Megabytes.
Theory and Measurements of Fates of H2S Scavengers
Authors: Elliott J. R. , Raymond M. B. , Kalpakci Bayram , Magri N. F.
Published: December 2007

The partitioning of the H2S scavengers/biocides, glutaraldehyde and acrolein, between the oil and the aqueous phases has been determined. The effect of the presence of salt on the partition coefficients has also been studied for salt concentrations from 0 wt% to 10 wt%. Acrolein was found to partition 47% to 66%, and glutaraldehyde

2% to 0.3%, to the organic phase, in a heptane/brine system. The effect of aldehyde concentration has been evaluated, from 2-10 wt% for acrolein and 5-50 wt% for glutaraldehyde. Theoretical analysis has been achieved, correlating the acquired experimental data and available literature data using the Elliott, Suresh, Donahue, equation of state1 (ESD-EOS).
Characterization of High Molecular Weight Compounds —Implications for Advanced-recovery Technologies
Authors: Wavrek D. A. , Dahdah N. F.
Published: December 2007

The failure of traditional methods to predict the precipitation of solid phases can be partially attributed to an inaccurate understanding of the molecular composition of the high molecular weight (HMW) components. This paper reports our progress in developing analytical techniques for direct determination of compounds up to C90 with readily available instrumentation. We believe this technology will help lead to production strategies that are more efficient and allow better estimates of production costs by more accurate forecasting of production problems.
Asphaltene Dispersants as Demulsification Aids
Authors: Manek M. B.
Published: December 2007

Destabilization of petroleum asphaltenes may cause a multitude of problems in crude oil recovery and production. One major problem is their agglomeration at the water-oil interface of crude oil emulsions. Once agglomeration occurs, destabilized asphaltenes can form a thick pad in the dehydration equipment, which significantly reduces the demulsification rate.

Certain polymeric dispersants increase asphaltene solubilization in hydrocarbon media, and when used in conjunction with emulsion breakers, facilitate the demulsification process. Two case studies are presented that demonstrate how asphaltene dispersants can efficiently inhibit pad formation and help reduce demulsifier dosage. Criteria for dispersant application and selection are discussed, which include the application of a novel laboratory technique to assess asphaltene stabilization in the crude oil. The technique monitors asphaltene agglomeration while undergoing titration with an incompatible solvent (precipitant). The method was used to evaluate stabilization of asphaltenes in the crude oil and to screen asphaltene dispersants.
Education Needs of the Oil Industry's Engineering Staff
Authors: Smith Charles R.
Published: December 2007

From the humble beginning of the oil industry at Titusville, Pennsylvania, in 1859 to the giant that it is today, the use of the professionally educated individual has been a professionally educated individual has been a mainstay of the energy business—be this in companies, in governmental agencies, in consulting groups, or in the universities. The dominant role of the engineer dictates that he be current and be capable of adjusting to the evolving technology. Responsibility of continuing and renewal education lies with the individual, with needed support from the employer, the professional societies, from the universities, and from the various entities that provide educational services. There is reason to behave that an arbitrary two-week reeducation period per year, with a sabbatical leave of six months (minimum) every five years, should be the goal of the aggressive engineer, the requirement of each and every employer, and the personal goal of each self-employed engineer. Additional regional continuing education centers need to be established—similar to the Kellogg Center at the University of Oklahoma.

Introduction

Much has been said about the state of the engineering profession—especially after the launching of the first Sputnik. Since this historic date in 1957, the applied sciences have received much attention and considerable federal funding, though not necessarily in areas directly benefiting the oil industry. However, the United States' emphasis on space technology did culminate in the landing of two men on the moon in July of 1969. With less journalistic impact, but with more direct benefit to the man on the street, the oil industry has managed to provide the world with an economical energy source that has primarily changed lives for the better. Of the problems that have been created, pollution is now receiving the most attention. Much of the solving will be done by engineers of all ages but mainly by those who have remained mentally flexible and who have kept on top of, or at least current with, advancing technology. Where did it all begin?

Background

It may be speculated that education began with the drilling of the Drake well in Titusville, Pennsylvania, or possibly before this date. A sizeable patent literature existed prior to 1900. Uhl points out that by the prior to 1900. Uhl points out that by the early 1900's, engineers and geologists were transmitting to their apprentices, through articles and through informal courses and study groups, the knowledge gleaned from the actual drilling for and the production of oil and gas. Early AIME and USGS publications became the main recorder of such activities.
The Effect of Surface Active Agents on the Relative Permeability of Brine and Gas in Porous Media
Authors: Conway Michael W. , Smith Kevin , Thomas Todd , Schraufnagel Richard A.
Published: December 2007

Surface active agents are included in most aqueous treating fluids to improve the compatibility of aqueous fluids with the hydrocarbon containing reservoir. A review of the literature indicates very little core flow data to describe the effects to be expected. Traditionally, it is believed that the reduced surface tension will reduce capillary pressure and enhance the recovery of water after the treatment. The reduced water saturation is then believed to result in higher effective gas saturation and higher relative permeability to gas after the treatment.
Scanning Probe Microscopy: Sulphate Minerals in Scales and Cements
Authors: Hall Christopher
Published: December 2007

The principles of scanning probe microscopy (SPM) are illustrated with examples from oilfield mineralogy, particularly emphasising sulphate minerals involved in scale formation and cement hydration chemistry. The topography of the (010) cleavage surface of gypsum observed by atomic force microscopy shows atomically flat terraces separated by shallow steps often only one unit cell high. SPM allows direct observation of processes on mineral surfaces while they are in contact with solutions. The dissolution etching and crystal growth of gypsum and barite are discussed and rates of step migration estimated. The orientation of steps is related to the crystallographic axes. The action of phosphonate crystal growth inhibitor on gypsum and of a chelating scale solvent on barite are also shown. The multiphase microstructure of an oilwell cement clinker is described in relation to its hydration chemistry in contact with water and its reaction with sulphate ions.
Examination of the Change in Returning Molecular Weight Obtained During Inhibitor Squeeze Treatments Using Polyacrylate Based Inhibitors
Authors: Graham G. M. , Sorbie K. S.
Published: December 2007

Scale inhibitors based on small polyelectrolytes are often employed in oilfield scale prevention treatments. These materials are injected into the near-well formation of producers in a scale inhibitor "squeeze" treatment. When the well is brought back on production, the objective is for the return concentration level of the inhibitor in the produced brine to be at or above a certain threshold level, Ct. This threshold level is the minimum inhibitor concentration required to prevent the formation of mineral carbonate or sulphate scales in that well. The squeeze lifetime depends strongly on the nature of the interaction between the inhibitor and the formation either through an adsorption or "precipitation" mechanism. Both adsorption and precipitation processes depend on the molecular weight of the scale inhibitor, as well as on a range of other factors. However, polymeric inhibitor species always display some degree of polydispersity (spread of molecular weight).

In this paper, we examine the effects of molecular weight on adsorption/desorption phenomena for polyacrylate based inhibitor species. This work shows that, in the inhibitor effluent after a squeeze treatment, the molecular weight of the returning inhibitor may be different from that which was injected. For commercially available polymeric inhibitor species, we demonstrate using core floods that preferential retention of higher molecular weight components occurs and preferential desorption of lower molecular weight components is observed. This leads to a gradation in molecular weight in the return profile, which can lead to increased molecular weight components returning as the inhibitor concentration approaches the threshold level. The significance of this observation to field application of polymeric inhibitor species is discussed.