bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Injection Technique to Develop Rim Oil, Mereenie Field, Australia
Authors: Kabir M. , McKenzie P. , Connell C. , O'Sullivan T.
Published: December 2007

The Mereenie Oil and Gas Field, situated in the Amadeus Basin in Central Australia, is the largest onshore oil field in Australia, containing some 367 million barrels of original oil in-place and 900 billion cubic feet of original gas in-place. Oil is contained in an elongated, anticlinal trap in multilayered reservoirs as rims associated with large gas-caps. Expansion of solution and gas-cap gas is the primary oil recovery mechanism. However, most of the oil is contained in narrow, thin rims in tight reservoirs which are considered marginally economic for development.

The Pacoota Sandstone is the major oil bearing unit The rims have been partially developed by drilling wells at a one kilometre spacing. The Pacoota Sandstone is Cambro-Ordovician in age with six to nine percent porosity and 5 to 50 md permeability. Dedicated production wells have been drilled for the upper and lower reservoirs at an optimum distance from the gas-oil contact to maximise primary recovery. Based on production performance, the average, primary oil recovery factor in the developed rim area is estimated at 28% of the original oil in-place.

A previous reservoir simulation study had indicated that two to three percent incremental oil recovery could be achieved by reinjecting the produced gas into the gas-cap. Recent modelling has shown a 10% to 14% incremental oil recovery by reinjecting gas directly into the oil rims. This innovative rim injection technique provides direct displacement of bypassed and unaccessed oil as well as pressure maintenance. The optimum spacing (between producers) for this gas injection technique is estimated at 1.5 km compared to 1 km for the primary development Simulation modelling shows that, unlike primary oil recovery, this secondary recovery is less dependent on well distance from the GOC.

A pilot test is currently underway. Based on the encouraging results from the pilot test and simulation results, a field development strategy is proposed.

P. 153
Current Plans, Future Prospects and Technology Challenges for Developing Oil Fields in Blocks 01 & 02, Cuu Long Basin Offshore Vietnam
Authors: Ramachandran S. , Thuy V.T.C.
Published: December 2007

This paper describes current plans, future prospects and technology challenges envisaged by Petronas Carigali Vietnam Sdn. Bhd. PC(V)SB in developing the oil fields in Blocks 01 & 02, offshore Vietnam. Following the signing of the Production Sharing Contract (PSC), PC(V)SB as operator and contractor to Vietnam National Oil and Gas Corporation (PetroVietnam), was entrusted to explore and develop any potential commercial discoveries in the Blocks 01 & 02 of the Cuu Long Basin in Vietnam.

The majority of oil discovered to date has been found in Tertiary sandstone and complex Pre-Tertiary age fractured granitic basement reservoirs. The Ruby field, its first commercial discovery will be developed in two stages. The phase I or pilot production phase project development plans are currently underway where first oil is expected to come on stream sometime end of this year. Valuable static and dynamic information obtained from the pilot phase will then be used to formulate the Ruby full field development plan. The other smaller discoveries of Emerald, Pearl and Diamond fields are currently seen as sub-commercial for a standalone development. As such the development of the Ruby field is seen as vital, as it will form the hub for future infrastructure integration and aggregation in order to commercialise the smaller fields.

New and sophisticated technology application will be required for production monitoring, prediction and reservoir management from the fracture granite basement, hydraulic fracturing and drilling extended reach wells to maximise ultimate recovery and to further reduce the overall development cost.

Additionally, in order to minimise flaring and to help recover the associated gas economically, a gas gathering scheme to collect and process the associated gas for the growing Vietnam gas market demand will be looked into as part of the Blocks 0 1 & 02 full field integrated development plan.

P. 185
Planning, Execution and Lessons Learned From the GWA13 Extended Reach Drilling Well - Goodwyn Gas/Condensate Field, NWS, Australia
Authors: Dolan S.P. , Crabtree R.C. , Drury R.F. , Gogan R. , Hattersley G. , Hindle D. , Neufeld B. , Scaife R.
Published: December 2007

GWA13 was the last well during Phase 1 of the development of the Goodwyn field and was drilled to a total depth of 8420m (27620') AHD with a horizontal step out of 7372m (24190') at a TVD of 2866m (9400').

The paper describes the planning processes before spud, and the equipment, techniques and directional control used during the drilling phase. Lessons that can be applied to both our own and other operations will be listed. The team approach to the drilling of Goodwyn wells will be emphasised and the risk assessment measures used both in the office and on the rig will be detailed.

P. 271
Head-hunting - Head-counting : A Perspective On Responsible Recruitment
Authors: Duce Grenville
Published: December 2007

The aim of this paper is to illustrate how the radical changes that have occurred within the global oil and gas industry over the past decade, have impacted on the areas of employment and career development. Like the oil market, Petroleum Engineering is not constrained by boundaries and the changes we have seen in Australia are not unlike those seen elsewhere such as Europe and North America.

A number of influencing factors which brought about change include:

– The collapse of the oil price in 1986 and continued restricted oil price – A decade of limited graduate intake and training – A decrease in the number of experienced professionals – The trend toward higher productivity performance through technology – A new focus on competencies and capabilities

These changes require a fundamental shift in the way in which the industry recruits, selects and ensures the on-going supply of well-trained people. This paper will cover past events and practices, the lessons learned and how those lessons can be translated into "Making a Difference" for the ongoing viability and sustainability of a company's development and potentially, the industry as a whole.

P. 416
A Small Joint Venture Operator's Approach To Intergrated EH & S Management
Authors: Kegg Brian
Published: December 2007

Throughout the mid 1970s, 1980's and early 1990's West Australian Petroleum Pty Limited (WAPET) introduced a number of individual initiatives in an endeavour to better manage its EH&S performance. A number of these initiatives such as STOP For Safety, Contractor Management, Quarantine Procedures, and Incident and Injury Reporting and Investigation etc. have been modified over time to cater for changes within the organisation, but are still in use today. However, it has been the move towards an integrated Environment, Health and Safety Management System (EH&S MS) and Safety Cases for the producing assets that has demonstrated consistent beneficial trends in EH&S Performance.

The development and implementation of WAPET's current EH&S MS, and Safety Cases for its producing assets represents a significant investment in both monetary and personnel resources and the drivers for such changes both internal and external, as well as the impacts and outcomes need to be understood by others contemplating a similar approach to EH&S management.

P. 441
New Completion Techniques Applied to a Deepwater Gulf of Mexico TLP Completion Successfully Gravel Pack an Openhole Horizontal Interval of 2400 Feet
Authors: Duhon Pete , Holley Alan , Gardiner Nick , Grigsby Tommy
Published: December 2007

As the scope of development continues to expand, more instances are being noted in which traditional technologies cannot satisfy job parameters. In deepwater projects, for example, high-rate production and completion reliability present major challenges to operators, and traditional methods of sand control often have not been able to address the changing conditions. In this paper, a solution that combines gravel packing, enhanced downhole tool capability, and advanced fluid technology is used in an offshore environment in which the completion was performed in a horiontal openhole extended-interval wellbore from a deepwater tension leg platform (TLP). New gravel pack tools and procedures were developed to meet the stringent requirements of the proposed scenario and will be discussed. The successful application of the first extended horizontal openhole gravel packs in the Northern Gulf of Mexico has proven that gravel packing can be successfully applied to extended horizontal wellbores.
Sand Control in Open Hole Horizontal Wells-Case Histories and Developments
Authors: Rovina Paulo S. , Filho Everaldo Lima
Published: December 2007

The discovery of new fields in the Amazon forest and in deep water offshore Campos Basin led Petrobras to adopt non conventional sand control completion techniques. The main goals were increase productivity, delay gas/water conning and support unconsolidated formations in water injection wells.

This paper will describe the experience acquired running screens in 23 horizontal open hole wells in Brazil. Several improvements were made on the equipment, procedures and in the well design due to the problems faced during the execution of the jobs.

As a result, the main objectives were achieved and new trends were established aimed at deep water fields development.
Improved Productivity Justifies World Record Underbalanced Perforating Operation
Authors: Johnson A. M. , Bakker E. R. , Hungerford K.
Published: December 2007

A Dutch onshore gas well was drilled to a total depth of 5136m along hole (3700m true vertical depth) with a maximum deviation of 89 degrees. The well was completed with 7 5/8" 13 Cr tubing with a 7" cemented liner across the reservoir providing full bore access to the pay zone. Due to the very stratified nature of the reservoir the long term sustained production depended on achieving vertical connectivity with all the layers. In order to achieve this and to maximise productivity a 1 run underbalanced perforating operation was required. Due to coiled tubing limitations in this deep, high pressure well a Hydraulic Workover Unit was selected to deploy and retrieve the guns. A total gross interval of 1026 metres was perforated in one run utilising 3 3/8" deep penetrating guns and thereafter snubbed from the well under live conditions (460 bar at surface). To date it is understood that this is the longest section of guns conveyed, fired underbalanced and deployed out of a live well. This paper addresses the perforating technique selection, the planning and execution process, the major operational learning points and discusses final productivity results which demonstrate the validity of this technique.
Recent Developments in Geoscience for 3D Earth Modelling
Authors: Fontaine JM. , Dubrule O. , Gaquerel G. , Lafond C. , Barker J.
Published: December 2007

This paper discusses recent developments in the domain of Geoscience, which contribute to better 3D modelling of hydrocarbon fields. These techniques integrate geophysical, geological and reservoir engineering knowledge in the construction of a 3D earth model. The 3D-earth model brings consistency between views of the reservoir held by different subsurface disciplines. A common quantitative description of the reservoir is used for all calculations and interpretation studies. Starting with picked horizons and well data, a number of aspects of 3D earth modelling are discussed:

– Anisotropic seismic ray tracing is used for constraining the structural model and estimating uncertainties. – The geological model is constrained by 3D seismic data through geostatistical inversion. – 3D sedimentary modelling generates a 3D facies model incorporating sequence stratigraphic interpretation and geostatistical modelling rules. – Computer-aided history matching quantifies sensitivities through gradient calculation and uses this information to reduce uncertainties in the geological model.

North Sea and West Africa examples will be used to illustrate integrated applications of these various techniques. In conclusion, future integration challenges for 3D earth modelling will be mentioned such as time-lapse seismic (4D), four components seismic (4C), fault modelling, improved links between dynamic data and the initial geological model.

P. 13
Measurement of the Soret Coefficient in Crude Oil
Authors: Georis Ph. , Montel F. , Van Vaerenbergh S. , Decroly Y. , Legros J.C.
Published: December 2007

Very recent works show that thermal diffusion (Soret effect) can have a significant impact on the composition grading of thick oil reservoir. So far, neither satisfactory theoretical models of thermal diffusion nor reliable measurements of thermal diffusion coefficients is available. Lack of knowledge of the magnitude of thermal diffusion may lead to an incorrect estimate of GOC location and to an inaccurate estimation of oil and gas in place. In this paper, we illustrate the potential impact of thermal diffusion on the compositional grading of a real field, outline the objectives the SCCO project and detail the technical achievements realised in this frame. The key objectives of the SCCO project are the following: To measure accurately the Soret coefficients of crude oil samples held in reservoir initial conditions (p 350 bar, T 60 C), to develop appropriate compositional modelling algorithms taking into account thermal diffusion and using reliable values of the measured Soret coefficients. To provide undoubted values of Soret coefficients for testing existing and future theories or correlation laws on the thermal diffusion phenomenon. Practically, Soret coefficients in multicomponent mixtures cannot be measured on ground because thermal and compositional gradients unavoidably induce convective mixing. In the SCCO project, measurements of the greatest accuracy will be obtained performing the experiment in microgravify where buoyancy driven convection is absent. In the present configuration of the hardware, three different complex hydrocarbon samples will be processed. Experimental constraints imposed by the high pressure of the samples and by the microgravity environment require the development of original technical solutions. We describe the miniaturised thermal diffusion cells as well as the dedicated sampling interface with the GC for post flight analysis.

P. 57
Ageing: An Origin for Quicksands and a Predictive Tool for Sand Production
Authors: Razoaki R. , Kageson-Loe N. , Langdon N.J. , Stokken-Ostby G.
Published: December 2007

Ageing is a geotechnical term which describes the changes in compressibility and strength characteristics of granular materials over lime. The process can occur in both naturally and artificially deposited soils through a wide range of diagenitic processes including compression, creep, cementing, weathering and changes in pore water chemistry reflecting physical and chemical changes induced on the material either over engineering or geological time (Atkinson 1993). Ageing has both positive and negative consequences in that the material can either become more stable or more sensitive to subsequent changes in the ambient stress state. Sensitivity of the material is demonstrated by the susceptibility of the material to collapse under an increasing applied shear stress once an initial intrinsic (ageing related) resistance is overcome. Both the amount of collapse and initial stiffness increase with ageing time. Stability is demonstrated by increased shear strength and stiffness, no collapse is observed. The significance of ageing and its dependence on sedimentological properties has been demonstrated on engineering time scales but similar evidence had not yet been previously considered with respect to geological time.

Data is presented from laboratory experiments on saturated carbonate and silicate sands which demonstrate differing sensitivity to ageing over a short time frame under low effective stress conditions. From this it is inferred that ageing and its manifestation is dependent on the compression and creep characteristics of the sediment. The experiments were cdnducted in standard geotechnical triaxial apparatus. The materials were aged under isotropic and anisotropic (Ko) stress conditions.

The phenomena of ageing is described with respect to stress-strain behaviour, effective stress, material stiffliess and collapse potential. Consideration is also given to sedimentological properties and how they influence the ageing process.

In reference to the results presented the paper conjectures to the occurrence of loose/quick sands in geological sequences. These materials have remained stable over geological periods of time but demonstrate sensitivity and collapse brought on by changes in the ambient stress state due to hydrocarbon production. Although these materials tend to be stronger and have been subjected to much higher effective stresses and temperatures than those studied to date they show sufficient similarities in behaviour for inferences to be drawn. It is argued that quick/loose sands are the manifestation of sensitive style ageing over geological time. The identification of those sedimentological parameters which influence sensitivity during ageing will assist in defining those sandstone lithologies most at risk of quick sand conditions.

P. 73
Improved Reservoir Evaluation in Norway Wells from High-Resolution Producibility Measurements
Authors: Jacobsen S.J. , Phillips J. , Cheruvier E.
Published: December 2007

Traditional formation evaluation from well logs is centered around the determination of water saturation, Sw, from which an interpretation of the expected hydrocarbon and/or water production is obtained. At the edges of the saturation range, from approximately less than 30%, and then greater than 70% Sw, these interpretations are generally straightforward. But accurate reservoir evaluation requires that a proper production prediction be made at all calculated saturation values, meaning that the ambiguities plaguing the link between water saturation and water cut in the 30-70% Sw range must be resolved.

This paper discusses Norwegian wells where the essentially static notion of water saturation is converted to a dynamic interpretation of moveable water/hydrocarbon. The outputs of a magnetic resonance logging tool, the CMR Combinable Magnetic Resonance Tool, are analyzed for porosity fractions of free and bound fluids via a link to core- derived permeability. This is combined with the interpretation of resistivity-porosity logging for bulk volumes of hydrocarbon and water to provide a continuous produciblity evaluation of each phase over the extent of the reservoir.

Several case studies in North Sea sandstone reservoirs over a wide porosity-permeability range are presented. The technique is valid for both oil and gas, and examples of each are shown. Production predictions are benchmarked against DST, production, or wireline formation test results in all cases. The complication to NMR interpretation due to significant levels of clay minerals such as chlorite and glauconite in these formations is considered.

The operational issue of increasing the traditionally very slow NMR tool logging speed up to efficient levels is addressed and the continuous producibility estimation is shown to be feasible at "normal" nuclear tool logging speeds.

Conclusions include recommendations on methods of performing the enhanced produciblity evaluation on routine development wells which are not typically cored.

P. 81
Water-Alternating-Gas Flooding in Venezuela: Selection of Candidates Based on Screening Criteria of International Field Experiences
Authors: Manrique E. , Calderon G. , Mayo L. , Stirpe M.T.
Published: December 2007

Water alternating gas (WAG) injection schemes have become an important strategy for improved oil recovery (IOR) technique around the world, and have been the focus of interest in recent years in Venezuela. This drainage strategy is mainly planned according to the major concerns in Western Venezuela oil fields: optimizing gas resources and improving oil recoveries in the region.

As part of the support to identify those reservoirs that will be candidates to WAG flooding in this area of the country, an extensive review was carried out to describe the main reservoir management strategies implemented in WAG pilot, as well as large field projects in order to evaluate international field experiences, before expensive reservoir description, laboratory studies, economic evaluations and WAG pilot projects are carried out.

This paper briefly describes part of this review and also shows some screening criteria for WAG floodings. Data from successfull and unsuccessfull worldwide projects have been analyzed obtaining relevant information about crude oil and reservoir properties as well as gas injection capacities, incremental oil recoveries, among others. All these data have been compiled and the results are presented graphically; the relationship between them is discussed and compared with data of some of the reservoirs proposed for WAG floods in Venezuela.

It has been found that WAG projects must be initiated with injection pressures 24% greater than reservoir pressures unless the formation is deeper than 8000 ft. Additionally, incremental oil recoveries reported by those projects are higher for lower viscosity ratios and do not depends on injected solvent slug sizes. Finally, the authors discuss how this screening was useful as a first look to identify the actual reservoir and facilities of different fields located at the Maracaibo Lake (e.g. B-6-X.10 and VLE-305) and select them for closer investigation and planning WAG pilot projects or "WAG Field Laboratories".

P. 161
Application of a Multisegment Well Model to Simulate Flow in Advanced Wells
Authors: Holmes J. A. , Barkve T. , Lund Ø.
Published: December 2007

The need to simulate advanced wells (horizontal and multilateral wells and ‘smart’ wells containing flow control devices) requires a correspondingly sophisticated type of well model to be implemented in reservoir simulators. The model must be able to determine the local flowing conditions (the flow rate of each fluid and the pressure) throughout the well, and to allow for pressure losses along the wellbore and across any flow control devices. This paper describes an advanced well model in which the wellbore is divided into an arbitrary number of segments. The well model has been implemented in a black-oil reservoir simulator, and the paper describes two case studies which assess the performance of the model and use it to examine the effects of flow control devices on two types of well.
Potential Application of Oxygen-Containing Gases in Heavy Oil Bearing Reservoirs
Authors: Lakatos I. , Lakatos-Szabo J. , Bauer K. , Kosztin B. , Biro Z.
Published: December 2007

In the frame of the laboratory studies the effect of natural and recycled CO2 and different air/CO2 mixtures on chemical composition of crude oil and gas phase, the rheological and interfacial properties, the flow mechanism and the safety measures were analyzed. The tests were performed at reservoir conditions using formation rock, oil and gas samples. The oxygen content of the gas phase and the gas/oil ratio varied between wide limits. Both crude and asphaltene-free oil were used to determine the consequences of the low temperature oxidation.

The main observation of the laboratory studies is that detrimental phenomena using natural and recycled CO2 as a cap gas may not ensue even at long term contact of oil and gas. On the other hand it was also found that the oxygen content of cap gas had completely consumed by the chemical reactions (oxidation, condensation and water formation), and as a result nearly 9 % excess asphaltene formation was observed in both the crude and the asphaltene-free oils. The substantial increase in asphaltene content and the presence of colloidal water resulted in a measurable change in rheological and interfacial properties. Despite these factors the flow and displacement mechanism is ouly slightly influences if the reservoir is of fractured character and the oil is already highly oxidized or is still in prematured evolution state.

As a final statement it was concluded that application of natural and recycled CO2 is a reasonable reservoir engineering and technological concept at the Nagylegyel field. However, in certain cases the chemical reactions can be in-situ regulated without jeopardizing the recovery efficiency by re placing the CO2 or inert gases with oxygen-containing cap gas. In this way the application of the artificial gas cap concept may open new vistas in EOR operations in karstic and fractured reservoirs bearing medium or heavy crude oils even in those cases when natural CO2 or CH source is not locally available.

P. 183
Coiled-Tubing Technology: An Application of High-Pressure Jet Cleaning in a Deep, High-Temperature, Sour Marine Environment
Authors: Morrison D.W. , Hogan R.D. , Coats E.A.
Published: December 2007

High-pressure, coiled-tubing, jet-cleaning technology provided a Mobile Bay operator with a viable option to remove downhole scale and debris efficiently without adversely affecting the formation, the environment, or the well-completion tubulars. This paper will provide a complete and detailed discussion of the surface and downhole equipment needed to perform the high-pressure cleaning application. The paper also provides an overview of the computer simulations created to predict coiled- tubing stresses accurately and the equipment used to collect real-time data on coiled-tubing fatigue, applied pump and hydraulic pressures, tubing drag and buckling parameters, cleaning fluid characteristics, and high-pressure nozzle design.

Historically, well-intervention alternatives have been limited in the deep-sour environment of the Mobile Bay field, which lies off the coast of Alabama in the Gulf of Mexico. Such factors as the sour-gas environment, the great depth of the formations (22,000 ft), the excessive bottomhole temperature >400), the high wellhead pressure >5,000 psi), and stringent environmental regulations, present adverse conditions that challenge the use of conventional well-intervention and workover technology.

Recently, a Mobile Bay operator experienced barium-scaling problems in a deep well (22,000 ft) (Fig. 1). A conventional workover risked formation damage as a consequence of killing the well, and damage to the well's expensive exotic alloy completion tubulars during the pulling and reinstallation process. Conventional rig mobilization and day rates were also prohibitive, as were the associated environmental issues inherent in Mobile Bay operations.

P. 215
Conversion of an Unprofitable Multireservoir Gas/Oil Field Into an Attractive Development Object
Authors: Zakirov S. , Brusilovsky A. , Zakirov E. , Zakirov I. , Piskarev V. , Karlinsky E. , Smirnov B. , Doroshenko J. , Krylov V. , Shepkina N.
Published: December 2007

In 1997 it was fulfilled the production planning project of a field (henceforth called "A"), located in Nadym-Pur-Tazovskiy region of West Siberia (Russia). This field is presented by Valangin (lower Cretaceous) gas-condensate and gas-oil condensate deposits of a complex geological structure with fluid reserves, which are reported to be very hard to be withdrawn. Almost all fields in the North of West Siberia contain high-performing and high- permeable Senoman formations. If Senoman formation is presented and developed, it predetermines appreciable profitability even though the other lower formations are being put into development together with Senoman formation. Therefore, this project is rather unusual from that point of view, that for the first time in this region the opportunity of profitable development technology of the field is considered without using capacity of upper laying donor Senoman formations.

The development of such fields by conventional ways requires the large capital expenditures at a low economic efficiency lying outside of the acceptable profitability. Consequently, the search of new approaches has been required to alter the economic value of the field.

P. 245
4D Seismic: Synergy, Not Just Integration, of Geophysics and Engineering
Authors: Waggoner J.R.
Published: December 2007

Much has been said and published about time-lapse 3D, or 4D, seismic since the last EUROPEC meeting in 1996, most of which focuses on the geophysical processing issues of comparing two 3D images to detect meaningful changes. This is indeed a critical part of 4D, because without a meaningful time-lapse change, there is clearly no useful information derived from the 4D processing. Given a time-lapse change, however, the next issue, and equally critical, is how the change is used to impact reservoir management.

The often stated benefits of 4D include the identification of bypassed oil and untapped compartments. Visual images of the time-lapse change may be sufficient to identify such features in simple cases, but most reservoir production involves changes to fluid saturation and pressure, both of which generally change the seismic response of the reservoir rock. Distinguishing between a pressure change and a saturation change is critical to proper use of the 4D result.

Fortunately, the reservoir engineer often uses a simulator that can be used to model reservoir production and predict pressure and saturation changes. Through a history matching process that incorporates both production and 4D seismic data, an improved reservoir model can be generated that is conditioned to fluid movement between the wells. The improved reservoir model will increase the predictive capability of reservoir simulations, and hence increase the effectiveness of one of the reservoir manager's tools.

By utilising engineering tools and information in the processing and interpretation of 4D data, geophysics and engineering work together in a way that enhances the value of the geophysical result.

P. 301
Reservoir Monitoring Using Time-Lapse Saturation Logs and 4D Seismic Improves Drainage Understanding in the Gullfaks Field
Authors: Instefjord Rune
Published: December 2007

The Gullfaks Field has been in production for eleven years and 2/3 of the estimated reserves have been recovered. The Tarbert and Ness Formations, belonging to the upper part of the Brent Group, contain 44 % of the total STOOIP.

Several 3D reservoir simulation models have been made. Due to the structural complexity and horizontal barriers it has been very difficult to history match these models, especially for the Ness Formation.

Repeated cased hole saturation logs have been collected in two wells located in the same fault block with initially oil filled upper Brent reservoirs. Standard saturation evaluation was not sufficient to understand the flooding pattern between the wells. A method making it possible to distinguish between formation and injection water even though the salinities are fairly equal has been used in this study. This has improved the understanding of the water flooding in the area. As a result of this, one of the wells (B-3) was successfully re-perforated in a thin undrained zone in the Tarbert Formation.

In 1995 a new 3D seismic survey for reservoir monitoring (4D-pilot study) was acquired over the studied area. The most pronounced 4D effects are observed at top reservoir level and at the initial oil/water contact.

One well – drilled in 1997 – confirmed an undrained area as shown by our monitoring tools and our general knowledge. In some areas there is less agreement between the 4D data and other data such as in the area around well B-3, were saturation monitoring was performed simultaneous with the acquisition of the seismic data set. Here the 4D data is not in accordance with the saturation profile in the well.

In 1996 a new seismic data set was acquired over the whole field. This data set is also interpreted for reservoir monitoring purposes. These new data together with earlier collected data will help to locate the remaining oil in the Gullfaks Field.
Nonintervention Solutions to the Loss of Downhole Data in a Subsea Field
Authors: Lumsden P.J. , Batten A.H. , Phillips H.T.
Published: December 2007

The installation of permanent downhole pressure gauges as part of the Arkwright subsea development, was seen as the ideal solution to control escalating development costs and to satisfy reservoir performance monitoring needs. However, the failure of all nine pressure gauges, during the first seven months of field life, warranted the search for alternative methods of data gathering. This failure was compounded by the tight economic nature of the field necessitating a search for a method, or methods, outside those involving costly rig based well interventions. Initially, use was made of a combination of two-rate drawdown analysis techniques and wellhead to bottomhole extrapolations, which gave results consistent with those from earlier build-up analyses during periods when real' downhole data were available. However, this method soon became outdated with the onset of water breakthrough in two of the three production wells. An alternative method was identified which injected lift gas directly into the wellbore at the wellhead, completely displacing the in-situ reservoir fluid to the perforations. Reservoir pressures were then calculated from a static wellhead to bottomhole relationship based upon the lift gas properties and the conditions in each well. Initial testing of this method has proved encouraging.

P. 371
Open Hole Horizontal Well Cleanup in Sand Control Completions: State of the Art in Field Practice and Laboratory Development
Authors: Price-Smith C. , Bennett C. , Ali S.A. , Hodge R.M. , Burton R.C. , Parlar M.
Published: December 2007

This paper was prepared for presentation at the 1998 European Petroleum Conference held in The Hague, The Netherlands, 20-22 October 1998.
Drilling of an Intermediate Radius Long Lateral in the Dunbar Field
Authors: Charlez Ph.A. , Ryan M. , Brandie G.
Published: December 2007

This paper descrihes the drilling of an intermediate radius, long lateral side-track drain in the Dunbar field (Central Graben - North Sea) initiated from a low inclination (32.30) parent hole which had been drilled four years earlier. The main goal was to constrain the drain within the upper part of the UMS formation (Upper Massive Sand - Brent reservoir) over a distance of l000m from the parent hole. The kick-off (51 /30m DLS) was successflilly achieved in two runs and 48 hours using a short titanium downhole motor with a 30 adjustable kick-off (AKO) setting. Thereafter, 910m of horizontal drain were drilled in 4 runs (10 days) with an intermediate length motor (6 meters) and PDC bits making a total lateral length of 1000m. Actual torque and drag remained satisfactory and close to those predicted by drillstring models. The major part of the drain was drilled in rotary mode (only minor azimuth corrections in sliding mode were necessary). The lateral was logged (gamma, sonic and resistivity) in TLC mode. Finally, and according to the results of an advanced wellbore stability study (no sand production expected) the drain was kept open hole and the parent hole completed with a monobore 4 1/2" tubing.

D05z lateral is the first extremely long lateral drilled in the North Sea after such a dog-leg. The combination of high DLS (up to 51 /30m), TVD (3570m) and length (l000m) marks it as one of the most challenging wells drilled in the North Sea.

P. 379
Buoyancy Assist Extends Casing Reach in Horizontal Wells
Authors: Rogers H. E. , Bolado D. L. , Sullaway B. L.
Published: December 2007

This paper describes a case history of how a major operator operating offshore Louisiana, in the Gulf of Mexico, extended the casing-setting depth of a well by creating buoyancy in the leading section of the casing. The buoyancy was created when an air pocket was trapped between the float shoe on the end of the casing and drillable buoyancy-assisted casing equipment (BACE™) assembly located in the casing at a calculated distance from the float shoe.

Problems encountered when casing is run in a horizontal or highly-deviated well are compounded by the drag of the casing on the lower side of the wellbore. Adding buoyancy to the lower end of the casing string reduces friction between the casing and the wellbore, thus enabling the casing weight in the vertical section of the well to push the casing deeper into the horizontal section.

BACE assembly used to enhance buoyancy can present the following operational advantages: full casing inside diameter (ID) after releaselarge annular clearance between BACE assembly internal components outside diameter (OD) and casing IDthread-type anchoring system (no shear pins, holes in the case, etc.)

This paper presents calculations, equipment design, operational detail, and results of BACE assembly used on the operator's platform.
Multiphase Metering: Experimental Results From the Analysis of Acoustic Noise Through a Choke
Authors: Piantanida Marco , Mazzoni Agostino , Tanzi Alessandro , Hope Bjorn R.
Published: December 2007

In this paper we discuss the main experimental results obtained during the field verification tests of the Well Flow Analyser (WFA). The WFA is a multiphase flow meter developed by SENSORTEKNIKK (Norway) and ENI, with the support of NORSK AGIP and STATOIL. The WFA predicts the flow rates of each component (oil, water, gas) in the multiphase stream, by analysing the noise generated by the fluid when passing across a choke valve. The instrument has been tested extensively in real conditions in the Trecate test loop which is located in the Trecate - Villafortuna oil field, at about 60 Km from Milan. The system used for the tests is relatively simple: it consists of an acoustic sensor installed on a Willis choke and a signal processing unit controlled by a personal computer.

We highlight the main technical challenges that have been overcome and the performance of the instrument, as a result of the tests carried out in Trecate along 1997.

The development of the instrument required the application of advanced processing techniques, such as digital signal processing algorithms (Fast Fourier Transform, Wavelet transform), multivariate statistical analysis and the use of neural network models, to extract the information related to the multiphase flow from the acoustic spectra. The resulting instrument has been tested on a broad range of oil, gas and water flow conditions, providing flow rate estimations with an average error of 5%-15%.

Finally, we describe the benefits related to the application of the WFA to well testing measurements, as well as the problems related to its calibration.

P. 429
Development of an Oil-Soluble Scale Inhibitor for a Subsea Satellite Field
Authors: Wat Rex , Montgomerie Harry , Hagen Thomas , Børeng Raymond , Kotlar Hans Kristian , Vikane Olav
Published: December 2007

The formation of oilfield scales is often caused by the mixing of incompatible waters and/or by changing pressure and temperature causing a reduction in the solubility of the dissolved solids in the produced water. To inhibit scale formation chemical inhibitor typically operates by either nucleation inhibition or crystal growth modification, is added to the water. Almost all scale inhibitor chemicals are water soluble and are typically deployed continuously or by squeeze from an aqueous phase. In most circumstances water is the preferred carrier medium since it allows instantaneous mixing and rapid interaction with the scaling ions. However, for treating a water sensitive formation or a well with poor lifting energy, the application of a conventional water based scale inhibitor squeeze may have many drawbacks. These include extended clean up period, increased water saturation in the near wellbore area, cessation of production due to water ingress. Either of these can result in significant loss or deferment in the oil production. In this paper a new range of scale inhibitors which are solubilised in the hydrocarbon phase will be described. These new oil soluble scale inhibitors offer some advantages over the conventional water based products. Furthermore, unlike the oil ‘miscible’ products of the past, these new scale inhibitors do not contain any mutual solvent which sometimes can cause process upset during the backflow after the squeeze treatment. The paper will focus on the development of a product which is specifically designed for a sub-sea satellite field. Due to its unique properties some of the standard test methods and selection processes have to be modified. Special considerations on the treatment design are also needed due to the deployment constraints in the field.
Application of Computer Simulation Techniques and Solid Divertor to Improve Inhibitor Squeeze Treatments in Horizontal Wells
Authors: Jordan M. M. , Edgerton M. , Mackay E. J.
Published: December 2007

This paper presents field results from five scale squeeze treatments carried out on sub-sea horizontal wells from the Strathspey field in the North Sea. The development of a squeeze policy is outlined with the utilisation of laboratory coreflood data, computer simulation (SQUEEZE V Code) and the application of a novel solid divertor.

This paper outlines the practical difficulties in squeezing sub-sea horizontal wells and how some of the problems can be overcome. Some of the solutions that will be discussed include the use of variations in pump rates to encourage propagation of inhibitor along the well-bore, and the utilisation of fluid diversion techniques (both mechanical and chemical). The significance of production logging tool (PLT) data or good reservoir simulation data to evaluate the location of water production and any cross flow prior to a squeeze treatment design will also be stressed. Details of divertor selection, design simulation and the field results from the five squeeze design strategies that have been implemented will be presented.

From this series of field treatments it can be concluded that the wells have all been successfully treated with no process upset during flowback. No decline in the wells’ productivity was observed as a result of these treatments. This paper shows that by using divertor agents, and by integrating near well-bore calculations (SQUEEZE V) and PLT/reservoir simulation data, it is possible to squeeze scale inhibitors into sub-sea horizontal wells without the need for coiled tubing intervention from a diving support vessel.
Changing Chemophysical Properties of Formation and Drilling Fluid Enhances Penetration Rate and Bit Life
Authors: Hayatdavoudi A.
Published: December 2007

This paper focuses on solving drilling problems that includes slow penetration rate, hole tightening, and short bit life. The goals are achieved through the alteration of chemophysical properties of the plastic, troublesome shales (i.e. "gumbo" shale.) Our studies of these issues show that most efforts of the past concentrated more on enhancing the penetration rate through the manipulation of weight on the bit, rotary speed, and other variables rather than by changing the chemistry of rock and drilling fluid and their interaction. As evidenced by setting two world drilling records in 1997, we were able to drill deeper and cheaper by designing and using a new Modular Drilling Fluid System, (MDFS) for the purpose of solving costly drilling problems. The properties and functions of MDSF are as follows. (1) It contains, through a reaction, a host of "anion" radicals linked to esters. Having a low surface tension, the mud filtrate with these radicals diffuses in the shale/rock capillaries rapidly like an "Anionic Wedge." The excess anionic charge adsorbed on the clay fraction of shales and mud particles cause strong repulsive forces within the shale capillaries. These forces in the rock/fluid interaction area weaken the rock shear resistance which result in the enhanced penetration rate due to the removal of the "sticky balling" material from the drill bit. (2) Unlike ordinary surfactants, the MDSF deposits a long lasting and lubricating coat on the shale and mud particles. The chemical "coat" changes physical properties oft the shale and mud particles (i.e. the particles with low friction cause enhanced bit life and less abrasion of drilling equipment).

By applying the new technique of changing chemophysical properties of formation and drilling fluids to the modern drilling technology, the contractors have successfully drilled more than 400,000 ft of hole over the last two years. Both the contractors and the operators have realized the considerable savings over the comparable footage drilled in the past.
Injection Water Treatment at the Source: Biocide-Enhanced Corrosion Inhibitor Squeeze Treatments of Water Supply Wells in a Central Arabia Oilfield
Authors: Rosser H. R. , Nasr-El-Din H. A , Al-Shammari N. A. , Al-Dhafeeri A. M.
Published: December 2007

A novel inhibitor squeeze program has been applied to control SRB (sulfate-reducing bacteria) and microbially-influenced corrosion (MIC) in the injection water supply wells of a sweet, Arab Superlight oilfield located in Central Saudi Arabia. The treatment is based on a biocide-enhanced corrosion inhibitor squeeze, spear-headed by concentrated biocide, and is unique in attempting to affect control of SRB and MIC from within the aquifer supplying injection water to the system. Applications of the treatment were intensively monitored in the field to assess the rate of return of the chemical, and their effects on microbial populations in the wells. Non-surface active biocide components were produced back in short, concentrated slugs comparable to shock doses in pipeline treatment programs, providing effective short-term control of SRB activity in the water supply wells. Regrowth, however, resumes once the chemicals are flushed from the wells during normal production, limiting the effective life of the biocide treatment in these wells to 2–3 weeks. Amines are extensively adsorbed on clay minerals, and are produced back at low concentrations for extended periods of time. The data provide insight into the range of rock-chemical interactions that can occur when squeezing multi-component oilfield chemicals into a sandstone aquifer containing significant quantities of clay minerals. The investigation highlights the importance of effective microbiological control during initial drilling and completion operations, and the difficulty in treating established microbial populations in porous media with biocides developed primarily for pipeline systems.
Advances in Observation of Asphaltene Destabilization
Authors: Wang J. X. , Brower K. R. , Buckley J. S.
Published: December 2007

An optical observation cell was added to a mercury-free PVT apparatus to extend studies of the onset of asphaltene precipitation to elevated temperatures and pressures. Observations for asphaltic, paraffinic, and light to medium gravity crude oils are reported as a function of temperature, pressure, and mixing time. Precipitants ranged from heptane to propane.

Studies at ambient conditions have shown that the refractive index at the onset of precipitation is an important characteristic of oil/precipitant mixtures. Calculated values of refractive index as a function of temperature, pressure, and composition are being correlated to observations of asphaltene separation at elevated temperature and pressure, as a predictive test.