bluuebunny/crossref_metadata_2025_split huggingface dataset:
Management Decision for Mature Steam flood Area with Steam Eruption: An Integrated Approach of Technology and Economics
Authors: Sutadiwiria Gunawan , Luthfi Achmad , Miriawati Ira 
Published: December 2007

Abstract
One of the most challenging problem in reservoir management for mature steam flood Area in determining hydrocarbon potential left in the reservoir is the management decision for go and no go project.
Duri Area 11 is located in Central Sumatera and operated by PT. Caltex Pacific Indonesia. This area is the north from the primary Duri Steam Flood (Area 1, 2, 3, 4, 5, 6, 7, and 8). The Problem in mature steam area was the reservoir is heating up and has indication of smectite clay in Rindu formation, and experience of steam eruption in Surrounding Area (9, 10).
In fact, the oil recovery become lower and the production cost become higher. The Extensive analysis was needed starting from 4D Seismic, geology model interpretation, fault seal analysis, geomechanics, reservoir characterization, steam chest prediction and the economic before the government give approval to develop the field.
Phasing development option will be implemented to reduce the potential of loss money as a possible option. The integrated high grading area was combined with economic analysis to propose reliable decision.
The change of development plan scenario will give different investment and producing in which initial POD was full development become phasing development. The changing plan will be affected to government and contractor share. The monitoring, and production analysis respond, steam temp, pressure and referable reserve at each phase development will support in improve production performance and economic field.
Based on the experienced and integrated approvals technology and economic, the real picture of development of Duri Field as a mature steam flood with unpredicted steam eruption has been solved and changed the no prospect development to prospect development.
Experimental Investigation and High Resolution Simulator of in-situ Combustion Processes; 1. Simulator Design and Improved Combustion with Metallic Additives
Authors: Gerritsen M. , Kovscek A. , Castanier L. , Nilsson J. , Younis R. , He B. 
Published: December 2007

Proposal
Accurate simulation of in-situ combustion processes is computationally very challenging because the spatial and temporal scales over which the combustion process takes place are very small. We present the design of a new simulation tool based on an efficient Cartesian Adaptive Mesh Refinement technique that allows much higher grid densities to be used near typical fronts than current simulators. The development of the simulation tool will be supported by extensive laboratory experiments conducted to provide validation data, and to study effective variants of the combustion process. In this preliminary report we show how metallic salt additives can promote and sustain combustion by enhancing the oxidation and cracking of hydrocarbons.
Adaptive Mesh Refinement reduces the dependency on grid size and empirically determined subgrid scale models, and allows a more accurate representation of the physics. Preliminary designs for a one-dimensional adaptive simulator which demonstrate the potential of this approach are given. The formulation presented serves as the foundation for the development of a three-dimensional simulator that can handle realistic permeability heterogeneity. Utilizing the multi-scale approach inherent in the simulator, more reliable and scalable subgrid models can be formulated and tested.
Using Empirically Developed Rock Tables to Predict and History Match Fracture Fracture Stimulations
Authors: Leshchyshyn T. H. , Beadall K. K. , Meier P. E. , Hagel M. W. , Meyer B. R. 
Published: December 2007

Abstract
Rock tables giving values for fracture closure gradient, Young's modulus, and Poisson's ratio have been developed by the authors using lithologies determined from well logs, cores and mud logs, and substantiated by numerous mini-fracs. Log curves are layered and analyzed for lithological intervals as thin as one foot. The various rock types are arranged in the table as a function of increasing closure gradient, giving a basic order of sandstone, siltstone, claystone, shale, and the group limestone-calcite-pyrite-anhydrite, dolomite and coal, all below the weight of overburden. Included in the tabulation are mixtures of the various lithologies derived in similar manner from formation logs. An example would be a carbonaceous-limy-sandy-shale having a closure gradient of 0.93 psi/ft (21 kPa/m), a Young's modulus of 2.18x106 psi (1.5x107 kPa), and a Poisson's ratio of 0.33. By comparison, clean sandstone has a closure gradient of 0.66 psi/ft (15 kPa/m), a Young's modulus of 3.33x106 psi (2.3x107 kPa), and a Poisson's ratio of 0.23. Over seventy identifiable lithologies or lithology-mixtures are listed in the table. All values were developed through a combination of rules-of-thumb and interpolation. This empirical data set is analogous to a seven-component, programmed log evaluation. A normal log analysis done manually will yield about fifty layers of rock with distinct compositions per fracture height equivalent to 100-165 ft (30-50 m) of depth. Layer-specific formation characteristics are then assigned to a fracture model for deriving initial shut-in pressure (ISIP) and closure. Next, the calculated results are compared to actual mini-frac data. If corresponding values show little similarity, then there exists some stress difference from normal behavior in the reservoir under study, the most common cause being pressure depletion. Variance is also attributed to such factors as dilation around the wellbore (cracks in the rock), tectonic strain, compressibility changes, density increase from silica diagenesis, and reservoir gas over-pressurization observed in mountainous regions of North America. In-situ stresses can be adjusted to properly model these particular situations. A separate set of rock tables was compiled for southern California siliceous formations where Young's modulus for diagenetically-altered diatomaceous rock ranges from 0.2 × 106 psi (0.14x107 kPa) to 1.0 × 106 psi (0.69 × 107 kPa). Unconverted diatomite, a regional lithology susceptible to depletion-induced compaction, exhibits a Young's modulus as low as 0.04 × 106 psi (0.028 × 107 kPa). Diagenetic sequences such as siliceous shale and porcelanite require special application of the California Rock Tables for depths to 8,000 feet (2,440 m), after which the standard Canadian Rock Tables for post-Precambrian formations can be employed.
Application of Water Based Drilling Fluid - Total Fluid Management
Authors: Jensen B. , Paulsen J. E. , Saasen A. , Prebensen O. I. , Balzer H. 
Published: December 2007

Abstract
North Sea area environmental practice and focus on reduction of drilling costs have limited the discharges of drilling fluid and drilling fluid chemicals to the sea the last years. A method for efficiently recycling water based drilling fluids has been developed. This recycling is conducted in a way beneficial both for the drilling fluid supplier and the operator. Contaminated fluid (slop) is brought back onshore for treatment and reusable fluids from the slop treatment are brought back into the drilling fluids.
The current paper show the total fluid management system operates for offshore drilling. This includes the compensation format being beneficial both for the drilling fluid supplier and for the operator. Furthermore, the paper describes the different actions taken to reuse water based drilling fluids, and how these actions generally reduce total drilling costs. The paper also describes the different systems implemented to minimize loss of drilling fluids and recycling of drilling waste streams. Also addressed are the challenges in establishing sound targets for optimum reuse depending on fluid systems, balancing economy and environment.
Offshore Rig Sharing Improves Exploration Drilling Performance: A Case History
Authors: Bert David R. 
Published: December 2007

Abstract
A jackup-drilling rig drilled seven exploration wells in the U.K. and Norwegian sectors of the North Sea during a two-year drilling program. By using sublet well commitments and assignments, the rig was secured in a very tight rig market. The drilling rig was shared between two Amoco (now a part of BP) business units for four wells and another major operator for three wells. The application of rig and personnel sharing produced over 10% (U.S. $12 million) cost savings to Amoco through shared lessons learned, continuous improvement, and reduced permitting time. An additional savings of over 10% (U.S. $12 million) was achieved through detailed planning and risk assessment that significantly reduced unscheduled-event (trouble) time.
Key factors for success of the program include continuous use of the same rig, crews, and offshore team members; the vision and support of management; adequate well design and pre-planning time; and the commitment of the right people with the right talents to the projects. The same Amoco wellsite supervisors were utilized throughout the program (even as the rig moved from operator to operator). This paper summarizes how the sharing of a rig, people, and best practices can improve exploration drilling performance, even across different teams, business units, operators, and countries. Examples of sharing knowledge between project teams are presented to quantify the value of a long-term drilling rig contract for one-off exploration wells. The paper concludes by providing lessons learned from rig-sharing agreements and future applications of rig sharing.
Correlations and Analysis of Cuttings Transport with Aerated Fluids in Deviated Wells
Authors: Avila R. , Pereira E. , Miska S. , Takach N. , Saasen A. 
Published: December 2007

Abstract
A study of cuttings transport at intermediate inclinations using aerated fluid, to determine the amount of solids that exist in the wellbore and minimum flow requirements for ‘clean-hole’ condition is presented. The experimental program included over 300 tests, performed with a large-scale facility (flow loop 100-ft in length, with 8" OD casing and 4.5" OD drillpipe). The angles of test section inclination were 30°, 45° and 60° from vertical. Four pipe rotational speeds (0, 40, 80, and 110 rpm) were used for different liquid and gas flow rate combinations. New correlations were found to estimate the required critical gas flow rates for hole cleaning at specified liquid flow rate and drill pipe rotation combinations, and to predict volumetric cuttings concentration as a function of air and water flow rate, drill pipe rotational speed and inclination angle.
Well Cleaning Performance
Authors: Saasen A. , Svanes K. , Omland T. H. , Mathiassen E. , Vikane O. 
Published: December 2007

Abstract
The removal of drilling fluids from the cased well prior to installation of critical completion equipment often involves use of special fluids and equipment to ensure a sufficient re moval of both the drilling fluid itself and particles attached to the casing wall. This is a critical operation where failure can lead to excessive complications in the subsequent completion operation with stuck packers or formation damage due to particle invasion into the formation as a consequence. Furthermore, these operations have the highest attention from the environmental authorities because casing cleaning operations are considered as highly polluting operations during drilling and completion of a well. Modern drilling fluids used in the North Sea region are designed to meet occupational hygiene requirements and environmental criteria. These drilling fluids are relatively difficult to remove from the casing surface.
The paper outline in detail an analysis on how the casing cleaning fluids could be evaluated in the laboratory. Thereafter, the effect of wall shear stresses on fluid displacement and well cleaning is described. The paper also outlines how different well cleaning fluids and mechanical cleaning equipment can be applied for different completion solutions. Thereafter, the paper describes displacement methods used to optimize removal of drilling fluid while producing as low as possible amount of drilling fluid slop fluid volumes. This minimization of slop is necessary to fulfil national environmental requirements.
Heavy-Oil Solution Gas Drive in Consolidated and Unconsolidated Rock
Authors: Tang G. Q. , Sahni A. , Gadelle F. , Kumar M. , Kovscek A. R. 
Published: December 2007

Abstract
Solution gas drive is an effective process to recover heavy oil from some reservoirs. However, characterization of the relevant recovery mechanism remains a challenge. In this work, we present an experimental study of solution gas drive of a 9°API crude oil with a composite core (consolidated) and a sandpack (unconsolidated). The composite core is placed in a stainless steel, Hasseler-sleeved type coreholder. A confining pressure is employed during depletion. The sandpack is made up of clean Ottawa sands with a grain size distribution similar to the reservoir cores. This sandpack does not employ a confining pressure and it is transparent to X-rays. Therefore, gas saturation development in the sandpack is monitored through X-ray computed tomography scanning. The live crude oil has a solution gas-oil ratio of 105 SCF/bbl and a viscosity of 258 cp at 178°F.
With the two different porous media, we investigated the effect of depletion rate and overburden pressure on heavy-oil solution gas drive. The results show that the overburden pressure affects heavy oil solution gas drive by offsetting partially the pore pressure decline. As a result, the apparent supersaturation in the sandpack is greater than that in the composite core. In addition, the measured critical gas saturation and oil recovery for the sandpack are greater than that for the composite core at the same depletion rate. The estimated gas relative permeability in the composite core is also greater than that in the sandpack.
Tracking Permeability in a Major Limestone Reservoir: from Rock Observation to 3d Modelling
Authors: Giot Daniel , Dawans Jean Michel , King Raymond , Lehmann Pierre , Shaw Ed , El Wazeer Fathy 
Published: December 2007

Abstract
Full-field static/dynamic models of a major oil and gas bearing limestone reservoir in a giant field onshore Abu Dhabi are being constructed to optimize reservoir management and to evaluate long term development options. An Integrated Reservoir Characterization and Modelling workflow is being developed with the primary objective of understanding and predicting permeability from reservoir to full-field scale.
To build a realistic 3D static model, the initial focus was set on geologically characterizing permeability at all scales by linking reservoir property distribution to reservoir geological characteristics. The ultimate static modelling objective is to derive 3D permeability distribution through the use of geological "filters" represented by Reservoir Rock-type (RRT) classes. In this way we aim to remove the need for global permeability multipliers, often found necessary in past simulation work to achieve satisfactory history matches.
The main steps of the selected Reservoir Characterization and Modelling workflow so far include:
– Definition of RRT and their vertical distribution from core data. – Establishing RRT lateral extension using sets of closely spaced wells, the results of outcrop analogue studies and lateral variography. – Prediction of RRT in uncored wells by use of neural network techniques. – Use of dynamic well data to corroborate permeability distribution and contrasts as derived from core study. – Generation of multiple 3D realizations of RRT distribution. – Investigation of porosity-permeability transform relationships to translate the 3D geological (RRT) model into the 3D property (permeability) model.
The 3D static modelling process uses deterministic and stochastic techniques with repeat testing of the model realizations by flow-simulation. It involves continuous iterative feedback looping between static and dynamic simulations, whilst progressing full-field model building. This method is seen as critical to ensure the timely delivery of a fit-for-purpose model that is in accord with geological, petrophysical and reservoir engineering data.
Technical Challenges Encountered During Coiled Tubing Underbalanced Drilling In Oman
Authors: Hoekstra T , Hopkins Chris , Fleck A , Bell G 
Published: December 2007

Abstract
This paper describes two of the major technical achievements during the first year of operation of a new, purpose built, underbalanced (UB) coiled tubing drilling unit (CTDU).
The unit is designed to drill sidetracks and extensions to existing wells to improve reservoir drainage. The package is fully self-contained, and uses native crude as the primary drilling fluid. Natural gas injection through conventional gas lift mandrels is used to maintain underbalanced conditions. The unit was built during 1998 and mobilised from the USA to Oman. Following final construction work and commissioning, it drilled its first well during February 1999.
This paper focuses mainly on two technical areas. Firstly, the world-record-breaking extended reach wells, including the challenges faced to achieve them. Secondly, the continuing project to minimise high water cut during initial production following workover. Details of operations are included, with an overview of drilling performance for the wells drilled in the first year of operation.
After 6 months of operation it was concluded that the production from slim hole wells drilled by the CTDU and conventional rigs was not as expected (high water cut). During this period a major review of the slim hole campaign took place, concentrating on cement placement around the 2-7/8″ liner and stimulation of the reservoir after perforating. This resulted in a major improvement of production and ultimately the continuation of the slim hole project.
The operator has drilled 21 wells to date with the CTDU and 9 more wells are planned for the year 2000. Technical contributions include:
Improved procedures and techniques for cement placement around a 2 7/8″ liner run on coiled tubing. World Record for longest horizontal section drilled with a coiled tubing (beaten twice – now at 1457m). Underbalanced drilling technology applied safely and successfully.
Underbalanced Drilling with Coiled Tubing
Authors: Matanovi Davorin , Meimurec Nediljka Gaurina , Krištafor Zdenko 
Published: December 2007

Abstract
The conventional overbalanced drilling of production zones generally results in a negative effect on overall productivity and cost, caused primarily by formation damage. As a result, the oil industry is turning more toward methods such as underbalanced drilling (UBD) to increase productivity and reduce overall costs.
UBD, particularly pressure-depleted, mature reservoirs, can minimise or prevent near-wellbore damage, often avoiding the need for stimulation.
A clear and fundamental understanding of drilling technology is required to design and supervise drilling operations on an underbalanced well.
The benefits of UBD technology, the use of CT (coiled tubing) in UBD, UBD fluid systems, control of the well while drilling are presented.
Recent Case Histories of Offshore Dual Multilateral Completion Systems in the Middle East
Authors: DeMong Karl , Rivenbark Mark , Bailey Ernest 
Published: December 2007

Abstract
Multilateral wells in the Middle East Region usually have been completed as non-access, single-selective or limited-access, dual-selective wells. These methods have limited the operator's ability to monitor and enhance a well's production and can lead to total loss of production during large-scale work-over operations. Advances in multilateral (ML) completion technology have developed unique completion systems that have the capability to connect horizontal laterals to parent well-bores and allow segregated production and intervention in new or existing well bores at any time in the life of the well. Recent multilateral wells in Arabian Gulf offshore fields have enhanced productivity using innovative techniques to satisfy the completion, workover, and intervention requirements of dual producing wells.
This paper will discuss case histories in which dual completions with and without pressure-isolated junctions (TAML levels 4 and 5) were developed and used. The completions were run in both new and existing wells, in both preplanned and workover scenarios. The operator's requirements were satisfied in each case. Their success has pushed the envelope for dual-lateral completion and workover in offshore fields of the Middle East.
The techniques discussed are applicable to Level 4 and 5 ML wells. The successes of these installations can be attributed to the dedicated team's pre-planning of contingency methods, drilling operations, wellbore preparations, components of the completion system, and running procedures. The case history data will identify the value gained from each stage of the planning strategy.
Dual multilateral completion technology includes various techniques for maintaining integrity in junction construction, completion configuration, and running techniques that combine to:
Facilitate multilateral technology application when varying production conditions exist in the same well Segregate a dual configuration for isolated or commingled production and dual segregated reentry Reconfigure existing commingled production for segregated production, isolation, reentry, and rig-less intervention Restore hydraulic integrity at failing lateral junctions Enhance effectiveness of production logging, stimulation, and rigless intervention for remedial operations Reduce initial construction cost and risk with a completion that considers the life-long production profile of the well.
Gas Masterplanning: Maximising Value from Integrated Gas and Oil Production Systems
Authors: McEwan Malcolm 
Published: December 2007

Summary
Complex oil and gas production systems offer major challenges and opportunities for maximising value from the supply chain:
Reserves –&gt; Infrastructure –&gt; Markets.
Gas Masterplanning is a process to maximise long term value of gas resources to enable competitive advantage and to provide the optimum integration of oil, gas, power, chemicals and other hydrocarbon opportunities.
Examples of criteria for developing a Gas Masterplan
Major increase in reserves with implications for infrastructure and marketing strategy. Marketing constraints requiring new outlets to develop reserves. Growing ullage in infrastructure offering opportunities for new deals / alliances / swaps. In a country or region where allocation of reserves to a limited market is required, or for value maximisation in the market place of limited reserves.
Masterplanning is a process as well as a product to ensure ownership by key stakeholders of the results.
The Gas Masterplan will show the envisaged development scenarios for the business, together with the opportunities and threats resulting from those scenarios in the context of changes to the business environment. It will detail the feasible and practicable alternative strategies available, the decision points between conflicting strategies and the recommended course of action.
Many ventures have benefited from masterplanning. A considerable database is now available on hydrocarbon value chain opportunities which enables benchmarking between ventures.