bluuebunny/crossref_metadata_2025 huggingface dataset:
Air Drilling Techniques
Authors: Cooper Leonard W. , Hook Roland A. , Payne Bobby R.
Published: December 2007

Introduction

The use of air or gas as a circulating medium was introduced in the early 1950's. Even though initial attempts were crude, significant increases in penetration rate and bit life were obtained. Since these initial attempts, development of air and gas drilling techniques have expanded and are widely accepted today as a method to reduce drilling times and cut cost of many wells. Along with the time and resultant dollar savings, other advantages such as immediate and continuous hydrocarbon detection, minimum damage to liquid sensitive pay zones, better control of lost circulation, and cleaner cores are obtained.

Today's air drilling technology is attributed to many drilling people whose initiative and accumulative experience have refined the method and determined situations where the technique is most applicable. The lack of understanding, rather than experience, is often the reason for not accepting air drilling. Drilling with air does involve special consideration in the use of equipment and drilling techniques that are not commonly encountered with other drilling media. For example, air, unlike fluids, compresses readily and requires a somewhat more sophisticated engineering approach to achieve the desired results.

This paper discusses the mechanics of air drilling, modifications such as mist or foam drilling, unique equipment requirements, and downhole problems that have been encountered. Special attention is given to presenting techniques developed to prevent or control downhole problems.

Discussion

Mechanics of Air Drilling

Air is the ultimate low density drilling media. In order to achieve optimum results and greatest economy from air drilling, there are several factors which should be considered. Hard formations which are dry or produce relatively few formation liquids provide the best results while air drilling. When the formation is completely dry, or the influx of liquids is slight enough to be absorbed in the air stream, the drill cuttings return to the surface in the form of dust. Also, this allows for immediate and continuous evaluation of hydrocarbons.
Delta Rig 76
Authors: McLean J.D.
Published: December 2007

America's energy outlook is an everchanging thing; however, with the construction of Rig 76 Delta Drilling Company is declaring its faith in the future of ultra-deep drilling in this country. In addition to design criteria and specifications, this paper discusses unique problems encountered-prime mover flexibility, testing of various components, mud handling and solids control equipment, moving considerations, foundation requirements, rig-up and start-up operations, and the outlook for activity both now and in the future.

Introduction

Rig 76 is a raised floor, elevated drawworks design costing in excess of $5,000,000 and requiring 52 machinery loads when moving. At the time of construction, this rig had the only 147 foot mast with a capacity of 1,555,000 pounds. There are seven other rigs now operating with this hook load capacity that have 142 foot masts. There are approximately 150 rigs with raised floor masts and approximately forty rigs with elevated drawworks; however, this is the only rig that has an elevated drawworks with this hook load capacity.

DESCRIPTION

The beam-leg mast has a 147 foot clear height with a 30 foot base at a floor elevation of 34 feet giving an overall height to the top of the crown of approximately 189 feet. Beneath the floor there is 27 feet of clear space below the rotary beams. With this design, the floor is actually built into the leg sections of the mast while the mast is at ground level in the horizontal position. When the mast is raised the floor is then at the 34 foot level.

Rig 76 is a diesel-electric eight motor rig having three motors on the drawworks. It has a working hook load capacity of 1,555,000 pounds with 14 lines strung and a simultaneous set back capacity of 800,000 pounds. The complete structure and the mast pounds. The complete structure and the mast is of A-441 (70,000 psi), alloy steel. The racking stand has capacity for 322 stands of 5 in. drill pipe plus ten stands of 9 in. drill collars. An additional 12 stands of drill pipe may be racked in the alley on the driller's side, giving a total racking capacity of over 30,000 feet. With pipe racked, the mast is designed to withstand 100 mph winds.
Nuclear Magnetic Resonance Log Evaluation of Low-Resistivity Sandstone Reservoirs By-Passed by Conventional Logging Analysis
Authors: Hamada G. M. , Al-Blehed M. S. , Al-Awad M. N. J.
Published: December 2007

The combination of conventional logs such as density, neutron and resistivity logs is proven to be very effective in the evaluation of normal reservoirs. For low resistivity reservoirs, however, an accurate determination of the petrophysical parameters with the conventional log reservoirs is very difficult. This paper presents two cases of low resistivity reservoirs and low contrast resistivity reservoirs where conventional logs fail to determine the petrophysical properties of reservoirs, mainly, low resistivity and low contrast resistivity reservoirs. The problems of these reservoirs is that conventional logging interpretation shows high water saturation zones, but water free hydrocarbon would be produced. In the case of low resistivity contrast reservoirs it is very hard to determine water hydrocarbon contact with resistivity logs. Nuclear magnetic resonance (NMR) has been only available as a supplement tool, to provide additional information on the producibility of the reservoir. The main limitation of NMR, however, has been the cost and time of acquiring data.

This paper shows that in the case of low resistivity reservoirs NMR is very cost-effective tool and helps to accurately determine the reservoir rock petrophysical properties. In the analysis of NMR data, several aspects of NMR technique have been used; 1) T1/T2 ratio for fluid identification, 2) the difference between NMR derived porosity and total porosity to determine the types of clay minerals, 3) NMR relaxation properties to identify fluids nature and rock properties. This paper presents four examples of low resistivity reservoirs. Analysis of NMR data of low resistivity reservoirs has helped to identify the producibility of these zones, to determine lithology independent porosity and to distinguish between bound and free water. For the case of low contrast resistivity reservoir where there was little resistivity contrast between water bearing formation and oil bearing formation, NMR has been able to identify the fluid nature of the two formations and then the height of the oil column. This was based mainly on high contrast of NMR relaxation parameters.
Effect of Gas Saturation on Oil Relative Permeability and Mobility Ratio in Reservoir Simulation using Different Methods
Authors: Kumar Rajesh , Shrivastava S. K.
Published: December 2007

Reservoir simulation involves validation through history matching. Relative permeability plays an important role to accomplish the task of history matching. In the reservoir simulators, there is an option to convert the 2-phase relative permeability data into 3-phase by using different methods. StoneI and StoneII are the two most commonly used for this purpose. However, ECLIPSE software for reservoir simulation has its own default method for segregated flow also, to calculate oil relative permeability.

In the present study, effect of gas saturation on the oil relative permeability and mobility ratio using these three methods has been discussed. The laboratory data from a carbonate reservoir of an offshore field of India has been considered. It has been observed that use of StoneII causes serious problems when it creates immobile oil saturation around the prolific producer wells. In fact, the oil saturation values were quite higher than their residual values at those places. This is because, in StoneII, the occurrence of negative oil relative permeability values implies a complete blockage of oil and as a result oil relative permeability equals zero. On the other hand, ECLIPSE default method give significantly higher values of oil relative permeability and very low values of mobility ratio in comparison to StoneI and StoneII methods over a wide range of gas saturation values. Further, use of this method yields close history match in those wells where they were ceased to produce due to oil blockage using StoneII method. In conclusion, selection of one of these methods should be done with due caution as all these methods have their own limitations and benefits at a given set of saturation values.
Learning from Offshore Decommissioning Practices in Europe and the USA
Authors: Dempsey M. J. , Mathieson W. E. , Winters T. A.
Published: December 2007

Decommissioning in Australian waters is a relatively new activity as only two installations have been fully decommissioned to date. The precedents set by decommissioning projects and regulations elsewhere in the world should be raising questions with the Australian operators and regulators such as the feasibility of an Australian rigs-to-reef program, the acceptabiity of dumping installations to sea, and the management of public concern. In considering these issues the Australian operators and regulators should not underestimate the value of information and experience that is available from the international forum. Information may be sourced from regulatory authorities, operators, personal contacts, in-house personnel with international experience, and literature and internet searches.
Platform Decommissioning Trends
Authors: Anthony N. R. , Ronalds B. F. , Fakas E.
Published: December 2007

Offshore oil and gas decommissioning experience to date, along with future trends, are explored by platform type and by region. There has been considerable decommissioning activity in the Gulf of Mexico, but generally only for small jacket and caisson structures. Partial removal, toppling, reuse and alternative use as an artificial reef are all common destinations of decommissioned platforms. In the North Sea, complete removal has been the preferred option, and this includes the largest platform chosen for decommissioning to date. Forthcoming cases including large concrete platforms will test this trend. Numerous floating facilities have been decommissioned in the North Sea and the majority have found reuse. Operators are also attempting to sell decommissioned North Sea jackets of moderate age.

Infrastructure offshore Australia is much less developed in comparison with the Gulf of Mexico and the North Sea and offshore facilities are smaller than the largest fixed steel and concrete platforms found elsewhere. Nonetheless, the largest jackets decommissioned to date around the world are only one-third the size of Australia's largest platforms. The local industry will watch with interest as decommissioning trends evolve in the early part of the 21st Century.
Evaluation Of Coalbed Methane Potential Of Jharia Basin, India
Authors: Peters James
Published: December 2007

Spurred by the commercial success of coalbed methane activity in USA, India initiated evaluating its coal bearing basins for their coalbed methane potential in 1992. In a short span of five years it tested and flowed coalbed methane from one of the coal seams of Barakar Formation in Jharia basin. This basin is one of the member basins of the Damodar-Koel coal belt of Eastern India. The basin cover an area of 450 square kilometers and exposes sediments of the Permian, Lower Gondwana Group. It is a half graben with the southern boundary fault being more pronounced than the northern boundary fault. The tectonic setting, physio-chemical, and reservoir characteristics, depth and thickness of coal seams, and production testing of one of the coal seams has resulted in demarcating the southern part of the basin to have an attractive coalbed methane play.

The central portion of this part of the basin has been prioritised for converting about 15 billion cubic meters of coalbed methane resources to reserves. Additional 15 billion cubic meters of methane resources could be converted to reserves from the adjoining areas.
Fracturing of the Miocene Sand in South Louisiana
Authors: Cross R.R. , Sheldon Lawson
Published: December 2007

The Miocene sands of South Louisiana have not responded to fracture treatments in the past, or the results have been limited and not past, or the results have been limited and not economical.

Using a two-phase gel system for efficient transport of high sand concentrations in the fracture coupled with high-pressure pumping equipment for placement at depths greater than 16,000 ft has increased the flow capacity and the recoverable reserves sufficiently to make the program economically attractive.

This paper describes the design, job performance, and results of this treatment. performance, and results of this treatment

Introduction

The M-24 Miocene sand is the deepest producing sand in the Venice Field, producing sand in the Venice Field, Plaquemines Parish, La. It is described as Plaquemines Parish, La. It is described as fine to very fine grained, firm to hard, and sometimes silty and shaley. Over all, the sand interval is generally comprised of numerous sand members separated by distinct shale breaks. Characteristically, the M-24 sand has low porosity and permeability, especially when porosity and permeability, especially when compared with shallower Miocene sands in the same field.

Venice Field is located adjacent to a large Salt dome. Fig. 1 is a map of the entire salt dome showing the position of the wells around it and those drilled through the overhanging portion of the salt. Cattle Farms A No. 3 is portion of the salt. Cattle Farms A No. 3 is almost surrounded by faults radiating from the salt dome (Fig. 2). This faulting is sufficient to limit the A No. 3 to a single-well reservoir. Secondary mineralization of salts around the dome eliminated all porosity and permeability in this area.

TREATMENT AND PRODUCTION HISTORY

Cattle Farms A No. 3 was completed in May 1975. Initial production through perforated interval (Fig. 3) 16,105 to 16,120 ft was 89 BOPD, 667 Mcf/D with a flowing tubing pressure of 300 psig. A bottom-hole pressure survey on May 31, 1975, indicated a flowing bottom-hole pressure of only 1,087 psig. After shut-in, pressure of only 1,087 psig. After shut-in, the pressure built to 5,487 psig in 7 hours, indicating wellbore damage or lack of permeability. permeability. Additional perforations in the 16,040- to 16,070-ft interval were added in another sand stringer to increase production.
The Deepwater Subsea Tieback Option for Future Oil and Gas Production in Australia
Authors: Heng E. I. , Ronalds B. F. , Edwards T. J.
Published: December 2007

The role of subsea tiebacks in the economic recovery of oil and gas world-wide is growing. Almost half of all proposed offshore field developments from 1998 to 2002 are expected to be unprocessed subsea tie-backs to surface production systems. With exploration and development venturing into deeper waters, the subsea tieback is proving itself to be a valuable option for the exploitation of these new oil and gas fields.

The design and subsequent operation of subsea tiebacks provides engineers with many challenges. One of the most important considerations is flow assurance. Some difficulties frequently encountered in subsea tieback systems resulting in flow assurance problems include hydrate and wax formation. This paper investigates the design of subsea tiebacks to provide optimum flow assurance, and discusses common strategies used to minimise hydrate and wax formation.

The Gulf of Mexico (GOM) is one of the three main theatres of deepwater oil and gas activity, where the number of developments exceeding 305m (1000ft) has grown significantly over the last decade. Recent deepwater GOM field developments are used to identify trends in subsea tieback developments.

Finally, the potential role of subsea tiebacks in future deepwater oil and gas developments in Australia is discussed. The exploration for oil and gas offshore Australia is moving into deep waters. Subsea tiebacks will play an instrumental role in the future development of these resource rich areas, where there is a lack of production infrastructure.
New Size-Controlled Microgels for Oil Production
Authors: Chauveteau G. , Omari A. , Tabary R. , Renard M. , Veerapen J. , Rose J.
Published: December 2007

New size-controlled microgels formed by crosslinking polymers under shear flow are very promizing for various applications in oil production. Indeed, when produced by using a proper polymer/crosslinker system and under the conditions needed to obtain the desired properties, these microgels should be quasi-ideal products. They are expected to control water mobility at long distances from the wells to improve sweep efficiency and reduce selectively permeability to water for water production control. For this latter application, injecting stable, preformed microgels eliminates the risks inherent to in-situ gelling which is a technique now recognized as being very difficult to control. This paper reports the results of new lab experiments conducted to complete our theoretical description of the crosslinking-under-shear process and to test the properties of these microgels in porous media. The actual properties of these microgels are compared to theoretical predictions. The results provide new theoretical insights into microgel formation and show that such microgels 1) have sizes measured directly by Photon Correlation Spectroscopy which are satisfactorily predicted by our model 2) adsorb quasi-irreversibly, forming adsorbed layers having a thickness equal to two times their viscometric radius of gyration, thus, are capable of controlling permeability more efficiently than the polymer alone 3) can be injected in porous media without any plugging tendency 4) have small internal rigidity as suggested by elastic modulus measurements and thus, they should be ideal disproportionate permeability modifiers 5) have viscosity higher than polymers in the dilute regime and extremely high in the semi-dilute regime, and 6) are stable, showing no tendency to re-form larger microgels when ageing, in presence of a suitable stabilizer.
Effective Chemicals For Microbial Control In Secondary Recovery
Authors: Huddleston Robert L. , Allred Ray C.
Published: December 2007

Publication Rights Reserved

This paper is to be presented at the Seventh Annual Meeting of Rocky Mountain Petroleum Engineers of AIME May 25–26, 1961, in Farmington, N. M., and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper.

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

In recent years the problem of biological control in secondary recovery has received a considerable amount of attention. In many cases, the success of a waterflood has depended upon the ability of the operator to control microbial growth.

The waterflood operator is faced with two basic microbiological problems:bacterial corrosion andmicrobial plugging of filters, flow lines, and water injection wells.

The waterflood operator must first establish that his problem is biological by a complete microbiological examination of the waterflood system. After finding that such a problem exists and determining the type of organism that is causing the problem, the operator is in a position to evaluate various chemicals for microbial control.

In most instances, nitrogen containing compounds such as quaternaries, amines, diamines, and imidazolines are effective in fresh water systems. The materials have the added qualities of being corrosion inhibitors and surface active agents. In general, the nitrogen containing chemicals are not effective in hard water systems. Chlorinated phenol type chemicals have proven to be effective in hard water brines.

Introduction

Microorganisms in secondary recovery waters are capable of creating problems which, if not controlled, could decrease operating efficiency and; reduce water injection rates. Waterflood operators must know how to detect these problems and how to combat them.
Drillbit SWD Reverse Walkaway Using Downhole Reference Signal
Authors: Naville Charles , Serbutoviez Sylvain , Throo Alexandre , Batini Fausto , Dini Ivano , Cecconi Fabio
Published: December 2007

Development drilling occurs sometimes in areas where the surface seismic quality is poor. Drilling in such areas is risky enough to justify the application of drillbit SWD for seismic illumination ahead of the bit. A multidisciplinary project partially supported by the EC was undertaken combining the following techniques:

Drillbit SWD, Seismic While Drilling survey using the drillbit as seismic source and many lines of surface receivers. The Bottom Hole Assembly (BHA) includes a roller cone bit, a shock absorber and a downhole reference sensor in between. EMWD, as Electro-Magnetic While Drilling wireless transmission surface to downhole. GEOSERVICES built a new Downhole Recorder Unit (DRU) integrated in the BHA in order to record the random axial drillbit vibrations in synchronization with a Surface Command Unit (SCU). Most of the commercial surface seismic recorders can be interfaced with the SCU. Large amount of uncorrelated seismic data are memorized both on surface and downhole while drilling, as the drillbit signal is available only when the drillstring is pulled out of the well.

The objective of the method is to produce a seismic image of the geological structure around the first well in order to confirm the target structure, or to indicate the drilling targets of the following directional wells. The field operation is limited to one or two drilling runs around mid-target depth, due to operational and cost constraints.

A full scale SWD reverse walkaway was recorded in this fashion around an ENEL well in a " no seismic result " area, near Larderello, using the OGS SEISBIT surface seismic recorder with 170 channels deployed over 6 radial lines.

The whole chain of field equipment behaved successfully and good seismic reflections have been obtained. The present SWD reverse walkaway technique does not disturb the drilling process significantly. The time delay for processing needs to be reduced in order to render the method even more attractive.
Dynamic Simulation of a Realistic 3-D Model of the Brent Slumps
Authors: Dijk H. , Arnott S. , Ozoglu S. , Pritchard D. W. , Price S. , Snippe J.
Published: December 2007

The Brent Slumps of the Brent Field were formed by crestal collapse of the main Brent reservoir during the late Jurassic. Production from the Brent Slumps has been dominated by two main factors: varying levels of connectivity with the West Flank of the field through cross-fault juxtaposition and preferential production via prolific high-permeability zones. Remaining Brent Slumps undeveloped reserves represent a significant fraction of the field total.

In order to improve the understanding of historical production performance and to address the remaining hydrocarbon volumes in place, a new realistically faulted 3-D simulation model has been constructed for the Slumps. The model contains over 140 listric and antithetic faults and utilises Shell's proprietary reservoir simulator (MoReS).

The model basis is a very fine cellular 3-D static model that contains a detailed description of both reservoir structure and facies-controlled permeability architecture. Simulation models are extracted at various scales, ranging from coarse (quick look at material balance and pressures), to very fine (investigation of flushing patterns), using upgridding and upscaling algorithms that guarantee consistency of volumetrics, connectivity and well data.

The simulation model is defined in terms of geological entities, i.e., individual faults, fault blocks, horizons and zones. This enables a high-level and systematic treatment of fault transmissibility and allows for monitoring of, e.g., material balance/pressures per fault block and flow across individual fault surfaces. This greatly facilitates sharing of simulation results within the multi-disciplinary development team.

The integrated static/dynamic model is now used to help identify and rank the portfolio of remaining development targets, in addition to underpinning the planning of complex, multi-target horizontal wells. Many infill targets are relatively small and lie close to the economic threshold. The improved technical integrity provided by the new model has been critical in providing sufficient confidence to support an infill drilling programme.

After outlining the particular development challenges for the Brent Slumps, the paper sketches the static model (seismic, analogues, structure, rock properties), explains the philosophy behind the integrated static/dynamic model and illustrates its utilisation (and successes) with a number of examples.
Hysteresis in Three-Phase Flow: Experiments, Modeling and Reservoir Simulations
Authors: Egermann P. , Vizika O. , Dallet L. , Requin C. , Sonier F.
Published: December 2007

A proper modeling of tertiary recovery processes such as gas injection or WAG (Water Alternating Gas) requires an adequate three-phase flow model. This allows to better predict the recovery efficiency, gas storage reservoir performance as well as the well injectivity.

For gas drainage, a previous paper [25] presented a new three- phase flow model based on a theoretical analysis and validated through experimental approach. For WAG injection, there is an additional complexity due to the need to model the imbibition that occurs when gas saturation decreases. To tackle the modeling of hysteresis problem, a comprehensive approach was followed. First, successive drainage and imbibition experiments were conducted under various conditions of initial saturations. A new three-phase model taking into account the hysteresis is presented and validated on the experiments.

Indeed, as shown in previous experimental studies, hysteresis was found to depend not only on the drainage/imbibition process (saturation history) but also on the cycle considered (displacement history) where cycle names the association of two consecutive displacements (drainage and imbibition). In this study, a relevant analytical expression of the hysteresis is proposed avoiding any negative effect of numerical instabilities. The new formulation was implemented in a reservoir simulator and WAG experiments have been successfully simulated. The impact on breakthrough time, overall recovery efficiency was tested through large scale reservoir simulations.
Vertilog - A Down-Hole Casing Inspection Service
Authors: Haire John N. , Heflin Jearald D.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

In California the shortages and resulting economics of new oil has intensified the search for new sources. With casing and drilling costs increasing, this search has resulted in a renewed interest and re-evaluation of many existing wells.

A knowledge of the condition of the existing casing is necessary for repairs, workovers, and possible developement of additional zones.

The Vertilog is a casing inspection service which is now available to the oil and gas industry to determine the condition of the casing in existing wells. It is a quantitative measurement of corrosive damage, indicating if the metal loss is internal or external, and if it is isolated or circumferential. Holes in the casing can be identified as well as parted casing. This survey in conjunction with other measurements, can be used to detect, monitor, and establish preventive techniques for corrosive problems.

This paper is intended to familiarize the industry with tool specifications, theory of operations, calibrations, applications, interpretation principles, and field examples.

Introduction

The Vertilog is a downhole casing inspection service. The recordings produced allow identification of damaged intervals and severity of corrosion. Measurements taken determine if corrosion or damage is internal or external and if it is isolated or circumferential.

Due to instrument design, casing inspection covers the full circumference and minor elongation does not elect the reliability of the measurements. Anomalies as small as 1/8" in diameter with as little as 20% penetration of the nominal bodywall of the casing penetration of the nominal bodywall of the casing can be detected.

All casing sizes, weights, and grades from 4-1/2" O.D. through 8-5/8" O.D., except 6-5/8" O.D., can be inspected at the present time.

The tools are temperature rated at 250 deg. F and pressure rated at 10,000 PSI. pressure rated at 10,000 PSI. The logging speed is 125 feet per minute and no special borehole fluids are required for the survey. It is recommended that the casing be scraped just prior to the survey for the most definitive measurements.

PRESENTATION PRESENTATION The data is presented in a standard log format, however, the usual depth scale is 10" per 100 feet of borehole for improved definition. The measurements are presented on a four track log grid as illustrated in Figure 1.

Track one and two are designated as Flux Leakage-1 (FL-1) and Flux Leakage-2 (FL-2) and correspond to the two rings of shoes on the Vertilog instrument. Recorder deflections in these tracks indicate the severity of corrosion that has taken place and also the location of the collars.
Constraining 3D Static Models to Seismic and Sedimentological Data: A Further Step Towards Reduction of Uncertainties
Authors: Marion D. , Insalaco E. , Rowbotham P. , Lamy P. , Michel B.
Published: December 2007

The prediction of the spatial distribution of petrophysical properties within a heterogenous reservoir is affected by significant uncertainties when based only on well information. However, integrating additional constraints such as 3D seismic data and sedimentary concepts can significantly improve the accuracy of reservoir models and help reduce uncertainties on predictions away from wells.

This paper addresses these issues with an approach for 3D modelling of static reservoir properties that involves the combined use of sedimentary modelling and seismic inversion techniques. The final results are multiple 3D petrophysical models with associated uncertainties. These models are coherent with the sedimentary model and consistent with seismic amplitude data. These results may then be used as an input to uncertainty analysis on static properties such as distribution of pore volume and hydrocarbon in place.

An example from a North Sea shallow-water siliciclastic reservoir is presented. This example demonstrates how integration of seismic and sedimentological can effectively influence the reservoir model both in terms of spatial distribution of reservoir properties and volumetric calculations.
Successful Multidisciplinary Teamwork Increases Income. Case Study: The Sleipner East Ty Field, South Viking Graben, North Sea
Authors: Hansen Helga , Westvik Kristin
Published: December 2007

Seismic and well data, such as cores, logs and production tests, are the vital input data used to build geological models for exploration and development of hydrocarbon fields. However, once a field is put on stream, production data itself gives valuable and important additional knowledge that improves geological insight and understanding. In particular, pressure observations, tracer data, together with production logs provide essential information about recoverable hydrocarbon volumes, communication routes, flow barriers, and drainage pattern within the reservoir.

A multidisciplinary team consisting of geophysicists, geologists, petrophysicists, reservoir and production engineers, together with drilling and completion engineers, cooperated for the last three years evaluating the Sleipner East Ty Field, which is a gas-condensate reservoir situated in the South Viking Graben, North Sea. During the work process, there has been a continuous feedback loop from the production data to the geological model. Changes of the geological model were carried out in order to match the dynamic reservoir model with actual production data. The resulting new models have been the basis for accelerated gas sales commitments and for increased condensate production from the reservoir. The integration of production and well engineers in the reservoir modelling team has lead to valuable focus on alternative drainage strategies, including drilling of new, challenging wells and more economically viable well interventions.
Reconciliation of Time-Lapse Seismic Data with Production Data for Reservoir Management: A Gulf of Mexico Reservoir
Authors: Huang Xuri , Will Robert , Waggoner John
Published: December 2007

Integration of time-lapse seismic and production data provides an effective tool for reservoir management. However, extensive work is required to build a "common" earth model1,2 honoring both types of data. This typically leads to longer turnaround times for time-lapse seismic projects. This paper demonstrates a method to shorten this time by reconciling production data with time-lapse seismic data in the data domain rather than in the earth model domain. The results from this method demonstrate that this quick evaluation can reveal whether or not the observed seismic differences represent reservoir changes associated with production, and can provide a basis for a more extensive model based evaluation. This method was applied to a gas reservoir in the Gulf of Mexico where preliminary rock physics modeling showed that water replacement would lead to more than 10% impedance change for approximately 30% of gas saturation change. The saturation-amplitude relation used to threshold the seismic difference volume was calibrated at the well or predefined locations. The threshold was optimized through solving the material balance relation obtained from production data with the time-lapse seismic data, thus making it more likely that the seismic differences are representative of saturation changes in the reservoir. This work: (1) provides a new procedure for gas reservoir time-lapse analysis under certain geological and production conditions; and (2) demonstrates a new first order method to reconcile time-lapse seismic data and production data without employing time consuming reservoir characterization and flow simulations. This approach greatly reduces the turnaround time involved in the use of time-lapse seismic information for reservoir management. Further, the result could lead to better subsequent model based analyses1,2.
Compositional Integrated Subsurface-Surface Modeling
Authors: Weisenborn A.J. (Toon) , Schulte A.M. (Tom)
Published: December 2007

Adequate modeling of a hydrocarbon production system may require integration of several reservoir models with a model for the surface network and a model for the processing facilities. The degree of detail in each model should be in accordance with its impact on the business case.

Compositional modeling of the hydrocarbon streams is usually highly desirable for volatile oils, gas-condensates and production systems in which different streams are mixed. However, compositional modeling is notoriously involved and CPU-intensive. Hence it has so far only been applied in an approximate way, with a few lumped components and reduced detail in the geological reservoir model(s). These approximations will often defeat the purpose for which compositional modeling was brought in.

Compositional modeling has been implemented in Shell#x0027;s proprietary Hydrocarbon Field Planning Tool to enable adequate modeling of gas-condensate and volatile oil systems. Surface network modeling was accomplished by interfacing with the compositional mode of the commercial network solver Pipephase. The compositional well streams were generated by extension of Shell's multi-purpose reservoir simulator MoReS with a delumping scheme. This scheme is in essence postprocessing of the well streams calculated on the basis of a two-component reservoir fluid representation. It requires a marginal amount of CPU time, independent of the number of components. In all applications so far the delumping scheme was found to be unexpectedly accurate: the mass rates of the 20-odd well stream components were reproduced with an average relative accuracy of about 0.5 %. The well streams consist of all components mentioned explicitly in the PVT report(s) and typically about 10 pseudo-components to represent the heavy fraction.

In this paper the physical considerations are described, which underly the delumping scheme. Also provided are a detailed validation study and the key results of field studies of gas-condensate fields in Australia's North-West Shelf area and in the North Sea.
Linking Reservoir and Surface Simulators: How to Improve the Coupled Solutions
Authors: Barroux C. C. , Duchet-Suchaux P. , Samier P. , Nabil R.
Published: December 2007

A full analysis of the problem of coupling two independent industrial simulators, a reservoir simulator and a steady-state network simulator, has been performed. A classification of the industrial needs has been obtained from the examination of several actual cases studies (fields at development, or production stage, requiring performance optimization through short to long term forecasts). Several coupling configurations and specific requirements, for both reservoir and surface software, have been identified to satisfy the industrial needs. Various commercial solutions have been screened to evaluate the adequacy between the software functional capacities and the identified configurations and requirements. Limitations have been brought to evidence.

The paper, issued from the work of a multidisciplinary team, presents the details of each step described briefly here above. Practical solutions for improving coupled solutions, i.e. to go beyond the identified limitations and to reduce the elapsed times of the coupled simulations, are provided. An improved mutual understanding of the needs of each discipline concerned by the integration of reservoir and surface has been experienced as essential for a successful integrated approach of field optimization. It is intended in the paper to contribute to a better communication between the various upstream petroleum skills: reservoir, production, surface and process engineers.
Water Management in a Closed Loop - Problems and Solutions at Brage Field
Authors: Andersen K. I. , Halvorsen E. , Sælensminde T. , Østbye N. O.
Published: December 2007

Brage field offshore Norway is producing off plateau at 8500 Sm3/d oil. Associated daily produced water rates are in excess of 16000 m3.

Following a change in injection scheme from seawater to aquifer water in 1997, two water supply wells were drilled and completed in the Utsira reservoir. Artifical lift from Utsira was achieved by installation of Electric Submersible Pumps. In parallel, the topside system was upgraded to facilitate complete PWRI (Produced Water Reinjection) in the Statfjord sandstone reservoir.

The Utsira aquifer, located 600 m below seabed, has showed excellent properties with respect to productivity and deliverability. ESP equipment installed in A-24 and A-29 has had a continuous improvement in reliability since 1998.

Topside, PWRI has resulted in wear on the injection pumps as a consequence of high particle content. Corrosion has lately been detected in the Utsira water producers, injection flowlines and 3 injection well tubings.

Sulphate scaling resulting from early seawater injection has been moderate at Brage. No problems associated with H2S have been seen following the change in water management philosophy. Carbonate scale in the upper tubing is successfully removed by a new acid deflection tool run on wireline while bullheading HCl. Bullhead squeeze treatments is utilized to control further scale buildup.

The closed loop approach to water handling at Brage has proven environmentally favourable, and has prevented the discharge of 9 500 000 m3 produced water to sea.
Evolution Tendencies of Physico-Chemical EOR Methods
Authors: Altunina L. K. , Kuvshinov V. A.
Published: December 2007

The evolution of physico-chemical EOR methods in Russia is connected with the use of oil-displacing systems capable to retain and to self-regulate a complex of colloidal-chemical properties optimal for the purposes of oil displacement. The dominating role belongs to EOR technologies increasing conformance by flooding or by steam-heat treatment. Promising are such physico-chemical methods, in which heat energy of the formation or that of the injected heat carier is used to generate in situ alkaline buffer systems and CO2, as well as to form gels capable to increase oil displacement and conformance. Hydrolysis, hydrolytic polycondensation and coagulation processes proceeding in the system carbamide – aluminium salt – surfactants – water are used to prepare inorganic gels. To prepare thermoreversible polymer gels one uses solution – gel phase conversion in the system cellulose ether with a lower critical dissolution point – water. Presented are the results obtained on the employment of physicochemical EOR technologies, developed at the Institute of Petroleum Chemistry SD RAS, in the oil fields of Russia. The tehnologies proved to be effective and ecologically safe. The period of payback is 5-12 months.
Contribution of the Coupled HydroMechanical Theory in the Estimate of Reservoir Production
Authors: Bévillon D. , Boutéca M. J. , Longuemare P. , Shahrour I.
Published: December 2007

This paper includes a study of the exploitation of soft highly compacting reservoirs using a coupled poromechanical model. The numerical results show that the exploitation of the reservoir induces instantaneous stresses in the totality of the reservoir, which produce pore-pressure variation in a zone located far from the pore-pressure diffusion area of the well. The evolution of the pore-pressure and the stress- and strain- paths are examined as a function of the stiffness ratio between the surrounding materials and the reservoir. The influence of the geometry of the reservoir (plane or axi-symmetric) and of the sideburden on the magnitude of stresses transferred by the overburden to the reservoir is also examined. Finally, the response of a heterogeneous reservoir is analyzed. The main results obtained with the poromechanical model are compared to those obtained with a conventional reservoir model.
Ranking R&D Projects in the Petroleum Area: New Tools for Economic Evaluation
Authors: Gottardi Giorgio , Maglione Roberto , Donati Franco , Broccia Patrizia
Published: December 2007

Recent non-optimistic fluctuations related to the oil price1 highlight the tendency of most of the oil companies in a cost-effective policy. The technology development is one of the key factors in the cost reduction strategy. As a consequence, the strategic scenario expected for the next future in the petroleum industry is an increase in finding new innovative technology solutions.

As of today in this scenario R&D activities, besides to greatly affect the strategic technologies portfolio, could have more influence than ever on the business.

However, future R&D projects could have an increasing onerousity and complexity related to greater technical and financing risks.

Introduction of new assessment techniques, in particular of economic and financial evaluation, might become decisive. In this paper a new tool supporting the selection of R&D project proposals related to strategical needs, expected economical benefits and expected redditivity, is shown. This is a computerised system that supports the decision-maker in the construction of the necessary estimates following an incremental procedure. R&D project are compared and ranked on the basis of a multiattribute evaluation. The economic and financial performance is evaluated on the basis of NPV, IRR and payback; probabilistic analysis and risk assessment also is carried out. Examples of ranking of R&D project proposals from internal R&D Dpt are also presented.
Mechanisms of Downhole Sand Cavity Re-Stabilisation in Weakly Consolidated Sandstones
Authors: van den Hoek P. J. , Kooijman A. P. , De Bree Ph. , Kenter C. J. , Sellmeyer H. J. , Willson S. M.
Published: December 2007

This paper presents a theoretical and experimental investigation into the possibility of cavity re-stabilisation after initial sand failure by formation of stable wormholes (‘pipes’) behind the casing / liner. Piping has been observed in dikes in The Netherlands.

A model has been developed to compute the degree of cavity re-stabilisation and associated sand production rates. The theoretical results show that formation of wormholes can result in re-stabilisation and associated reduction in sand production. The theoretical work has been verified by laboratory sand production experiments. Experiments on friable sandstones show that formation of wormholes can take place as part of a re-stabilisation process. Experiments in homogeneous unconsolidated sandstones, on the other hand, show that under elevated stresses, it is impossible to form stable wormholes in this case. Experience with dikes however show that wormholes in these sands can occur when they are interbedded with shales/clays.

The results above in homogeneous sandstone are further supported by tests with horizontal pre-drilled, uncemented liners in weakly consolidated artificial sandstones. Formation of stable sand arches over the liner holes takes place at low values of far-field stress. However, elevated values of far-field stress lead to a continuous, high-rate (‘massive’) sand production.
Specifying Lengths of Horizontal Wells in Fractured Reservoirs
Authors: Stowell Julia F. W.
Published: December 2007

When drilling a horizontal well in a fractured reservoir the aim is to intersect those fractures that are capable of providing a conduit for fluid flow. Key factors influencing the success of a horizontal well include the choice of horizon and the direction of drilling. However, even if these have been determined, the drilling distance required to achieve the aim remains a problem.

New methods have been developed which allow an appropriate drilling distance to be constrained on a site-specific basis, where opening mode fractures are dominant. These methods utilize knowledge gained through empirical studies of the scaling properties of fracture populations. Statistical constraints on the required well length are calculated through measurement of the aperture size distribution of the fracture population, combined with observation of the history of fracture fill. Calculations of fracture permeability are made, based on the scale of data acquisition and are compared with matrix permeability.

A case study of opening-mode fractures in the Austin Chalk reveals that large, potentially open, fractures are commonly clustered, the distance between clusters ranging from ~1m to ~50m. Aperture size distributions follow power laws and spacing size distributions are negative logarithmic or lognormal. The aperture size at which fractures are open to fluids is variable (0.14-11mm). Fracture permeability is dependant on the scale at which it is measured and has been determined at 7.1D (for 18m of Lower Austin Chalk core) and 286D (for 300m of Upper Austin Chalk outcrop). These calculated fracture permeabilities are several orders of magnitude larger than the typical Austin Chalk matrix permeability of 0.03-1.27mD.