bluuebunny/crossref_metadata_2025_split huggingface dataset:
Uncertainty in Geophysic-Geology-Reservoir Modelling for Globigerinid Sands Carbonate in the NE-Java Basin, Indonesia: Case Study: Planning vs. Actual Field Development in the Madura Strait, Indonesia
Authors: Sutadiwiria G. , Prasetyo H. 
Published: December 2007

Abstract
One of the most challenging problem in the Plan Of Development for developing the Globigerinid sands carbonate reservoir in determining hydrocarbon potential in the reservoir is the management decision for go and no go project.
In the North-East Java Basin Indonesia, Pliocene Globigerinid sands carbonate was proven as oil and gas potential reserves as found in MDA, TSB, O and M fields, which are operated by several PSC (Production Sharing Contract) companies. The last three fields are in the development phase. Uncertainty issues related to structure, stratigraphy, and pore system were critically influential factors for the success level in the development plan of the fields.
In fact, the results from development wells in one of the fields in the offshore of the Madura-Strait, have indicated a significant difference compared to the Plan of Development based on exploration and appraisal wells. The problems were compartment related due to structure-stratigraphy combination; variation of the depth of fluids contacts for each compartment; low-resistivity case in clean-oil zone; extensive fault development; change and correction of hydrocarbon in-place estimation. All issues above will change the economic of the field.
Based on the lesson learn, an extensive analysis was needed to reduce the uncertainty that influence the economic plan of development before the government grants an approval to develop the field or revised the Plan of Development. There were some identified critical factor to increase the success level for the optimal development of carbonate reservoir Globigerinid sands as follows: the 3-D seismic (multi-component) included inversion and attribute analysis, exploration and appraisal well numbers & type, production test data, laboratory analyses, integrated evaluation with other discipline and so on.
Based on the experienced and integrated approach, the real picture of development of any future fields that contain the Globigerinid sands carbonate reservoir with unpredicted uncertainty factors has been solved and made the economic prospect development became more realistic.
Well Test Analysis in Lean Gas Condensate Reservoirs: Theory and Practice
Authors: Gringarten A. C. , Bozorgzadeh M. , Daungkaew S. , Hashemi A. 
Published: December 2007

Abstract
Gas condensate reservoirs exhibit a complex behavior when wells are produced below the dew point, due to the existence of a two-fluid system, reservoir gas and liquid condensate. Different mobility zones develop around the wellbore corresponding respectively to the original gas in place (away from the well), the condensate drop-out, and capillarity number effects (close to the well). Condensate drop-out causes a non-reversible reduction in well productivity, which is compensated in part by capillarity number effects.
All these effects can be identified and quantified from well test data. Tests in condensate reservoirs, however, tend to be difficult to interpret. Build-up and/or drawdown data are usually dominated by wellbore phase redistribution effects and the main analysis challenge is to distinguish between reservoir effects, boundary effects, fluid behavior and wellbore phase redistribution perturbations.
The paper compares theoretical well test behaviors in vertical and horizontal wells as obtained from compositional simulation with actual behaviors selected from more than twenty different gas condensate reservoirs. An interpretation methodology is described, which uses time-lapse analyses, deconvolution and different analytical and numerical tools to identify the probable causes of the pressure data behavior: two-region and three-region analytical composite models to represent the various mobility zones around the wellbore; a voronoi-grid numerical simulator to represent discontinuous boundaries; a multilayered analytical simulator to account for the geological description and a compositional simulator to verify the fluid behavior. It is shown that, in addition to the usual well test analysis results, it is possible to obtain parameters required for reservoir simulation and well productivity forecasting, such as gas relative permeabilities at the end point, critical oil saturation, and the base capillary number.
Managing Structural Integrity for Aging Platform
Authors: Nichols N. W. , Goh T. K. , Bahar H. 
Published: December 2007

Abstract
Petronas Carigali Sdn Bhd (PCSB) is currently operating in excess of 150 Platforms. Of these over 60% have been in operation for more than 20yrs, 20% of platforms have already exceeded 30yrs with several others in the very near future reaching their initial design life (20-25yrs).
Increasing demand to extend the life of these platforms due to further oil/gas discoveries can result in the platform being subjected to higher loading due to required modifications/ upgrading and work-over demands for which the platform may not have been originally designed for. Furthermore, the need to undertake more frequent detail inspections due to long-term fatigue phenomena also requires managing.
In addition to the above PCSB platforms may also be faced with other challenges/events such as more onerous code requirements, increase in environmental metocean loading, presence of shallow gas and seismic/earthquake loading for which again the structure may have not been initially designed for. As such PCSB must be able to manage these events and justify the on going integrity and fitness for purpose of its platforms.
This paper describes the challenges and solutions faced in managing the ongoing long-term structural integrity of its ageing platforms. Several key assessment procedures, tools and technology initiative improvement programs will be covered in detailed to highlight their importance in managing the long-term integrity of the structures. In addition the implementation of such assessment procedures, tools and technology improvements are being used to assist in the ongoing development of a Carigali Structural Integrity Management System (CSIMS). The process adopted (as described in this paper) is to be inline with the recent development of a standalone Recommended Practice (RP) API RP 2SIM, for the Structural Integrity Management of existing structures (currently applicable to Gulf of Mexico), to extend its applicability to Non-US Waters. As such PCSB has recently joined a JIP (Joint Industry Project) initiative involving a number of Non-US Oil/Gas Operators to extend the applicability of the RP 2SIM to Non-US Waters.
New Integration Technique for Different Type of Data to Construct a Permeability Prediction Model from Well Logs
Authors: Otake Mayu , Shimamoto Tatsuo 
Published: December 2007

Abstract
This paper presents a new technique to integrate the different scales of data, Logs and PLT (Production Logging Tool). Low resolution of permeability measured by PLT (PLT permeability), which is about 10 times lower than that of logs, caused poor correlations among logs and permeability using any regression algorithms. In order to overcome this problem, PLT permeability was down scaled to the log scale and built a correlation using the ACE (alternating conditional expectation) algorithm. The log-derived permeability by this technique can express the complicate variation of permeability at the range of 0.001md to 1md. The result shows a good agreement with not only the PLT survey result and core data but also the mobility measured by wire-line formation tester (RFT or MDT).
Depositional Modelling of Champion Field, Brunei: Assessing the Impact of Reservoir Architecture on Secondary Recovery
Authors: Hadley D. F. , Arochukwu E. , Nishi K. , Sarginson M. , Salleh H. , Omar M. 
Published: December 2007

Abstract
Champion is a multi-billion bbl STOIIP oilfield offshore Brunei. It is a mature field with over 250 producing wells. Oil production commenced in 1972, and production to date is less than 20% of the oil initially in place. The feasibility of increasing recovery through a major waterflooding programme is currently under evaluation. Potential incremental oil recovery is 8%.
Significant capital investment (up to 140 new wells and 10 new jackets) will be required to realise this opportunity. It is, therefore, important to capture the full range of possible subsurface scenarios early in the study. A fundamental first step in the integrated modelling workflow has been to develop an understanding of the depositional and tectonic history of the field in order to create static models that capture the range of uncertainty in geometry and properties of the reservoirs. Data from core, well logs, seismic and outcrop analogues have been integrated to produce depositional models, highlighting uncertainties in reservoir architecture as they would impact potential waterflood recovery. Two broad types of reservoir interval have been recognised:
stacked shoreface parasequences, which form the majority of Champion reservoirs. In general, these comprise a gradational succession from basal offshore-transition zone heterolithics to amalgamated low angle cross-stratified sandstones of the lower shoreface zone. Correctly considering stacking patterns and degree of vertical connectivity between sands is important to the success of a waterflood. tidally-dominated sediments, comprising tidal channel fill or bar complexes set in a background of mud to sand-dominated tidal flat facies have been recognised. For these sediments, channel sand geometry, orientation and internal permeability anisotropy are crucial to predicting fluid flow.
The results of the sedimentological review have been used to create a series of 2D cross sectional dynamic simulation models, covering the range of depositional environments, and a range of connectivity scenarios. The main conclusion of this study is that water is the preferred injection fluid for all of the Champion field reservoir intervals studied. Water typically gives a 15-20% (absolute) higher oil recovery factor than gas.
The impact of the sedimentology review and modelling is that it will enable early selection of water as the injection fluid. This means that surface engineering work can focus on water injection scenarios, reducing the time required to identify a preferred development plan and accelerating project implementation.
An Experimental Study and Genetic Algorithm (GA) Correlation to Explore the Effect of nC5 on Impure CO2 Minimum Miscibility Pressure (MMP)
Authors: Bon J. , Emera M. K. , Sarma H. K. 
Published: December 2007

Abstract
Limited experimental work has been performed to study the effect of nC5 on Minimum Miscibility Pressure (MMP) when added to impure CO2 as an injection gas for flooding processes. Furthermore, current MMP correlations have been developed based on data where the injection gas contains no nC5 fractions. Consequently, their MMP prediction is not highly accurate when nC5 exists in the injection gas. In order to further investigate the effect of nC5 on impure CO2 MMP, this work presents the experimental investigation and subsequent development of a correlation to model this effect.
Using Rising Bubble Apparatus (RBA), MMP data points were measured on three reservoir fluids and four injection gases at three temperatures. The three reservoir fluids were relatively light with stock tank gravities in the range of 44-52 °API and GOR's 100-1300 scf/stb. The base gas composition was 92mol% CO2 and 8mol% C1. To this nC5 was added to create gases with 1mol%, 3mol%, and 5mol% nC5. The nC5 was noted to decrease the MMP.
Based on the experimentally measured MMP data set, a strong trend was found. The effect of addition of nC5 on the impure CO2 MMP has been correlated using Genetic Algorithm (GA). This correlation depends on the injected gas composition and critical properties. The GA-based correlation predicted the nC5 effect with greater accuracy than the currently available correlations, giving an absolute error of only 3.4%.
It is envisaged that this work can be used to investigate the possible benefits in retaining the nC5 fraction in the injection gas and to provide a method of evaluating whether it is worthwhile to add or retain a small amount of nC5 to the injection gas to improve miscibility with the reservoir fluid. Thus, more oil can be recovered and the added injection gas expense may perhaps be justified.
Reservoir Fluid Sampling Revisited—A Practical Perspective
Authors: Bon J. , Sarma H. K. , Rodrigues J. T. , Bon J. G. 
Published: December 2007

Abstract
PVT fluid properties are an integral part of determining the ultimate oil recovery and characterization of a reservoir, and are a vital tool in our attempts to enhance the reservoir's productive capability. However, as the experimental procedures to obtain these are time consuming and expensive, they are often based on analyses of a few reservoir fluid samples, which are then applied to the entire reservoir. Therefore, it is of utmost importance to ensure that representative samples are taken, as they are fundamental to the reliability and accuracy of a study.
Critical to the successful sampling of a reservoir fluid is the correct employment of sampling procedures and well conditioning prior to and during sampling. There are two general methods of sampling; surface and subsurface sampling. However, within these there exist different methods that can be more applicable to a particular type of reservoir fluid than to another. Further to this, well conditioning can differ depending on the type of reservoir fluid. Sampling methods for each reservoir type will be discussed with an emphasis on scenarios where difficulties arise, such as near critical reservoir fluids and saturated reservoirs. Methods including single-phase sampling and iso-kinetic sampling, which have been used increasingly in the last decade, will also be discussed with some detail as will preserving the representativeness of other components in the sample including asphaltenes, mercury and sulphur compounds.
The paper presents a discussion aimed at better understanding the methods available, concepts behind the methods, well conditioning and problems involved in obtaining representative fluid samples.
History Matching for Determination of Fracture Permeability and Capillary Pressure
Authors: Gang T. , Kelkar M. 
Published: December 2007

Abstract
For naturally fractured reservoirs, it is very difficult to quantify the future prediction without proper fracture properties and capillary pressure. Capillary pressure and fracture permeability can interact in a way which can produce non-unique results. For example, strong imbibition capillary curve with high fracture-matrix permeability contrast can behave similarly as weak imbibition capillary curve with low fracture-matrix permeability contrast. Evaluation of core data may provide us with some information about imbibition capillary pressure curves; however, quantification of fracture permeability is largely determined by matching the production data.
This paper presents an integrated approach to history matching of naturally fractured reservoirs by adjusting the fracture permeability of individual fractures and the water-oil capillary pressure curves. By matching production data by minimization of a weighted least squares objective function, we generate estimates of fracture permeability, and water-oil capillary pressure curves. All of implementations are incorporated into a commercial simulator (ECLIPSE) and iterated in the automatic history matching scheme. The adjoint method and an efficient direct solver were used to decrease CPU time for calculating the sensitivity coefficient matrix. A Middle East reservoir model was used to validate our method.
The Importance of Graphical Methods in Estimation of the Diffusion Coefficient of Gases in Bitumens and Heavy Oil
Authors: Sheikha H. , Pooladi-Darvish M. , Mehrotra A. K. 
Published: December 2007

Abstract
Graphical methods are important tools in estimation of the diffusion coefficient as well as identifying various stages involved in the ordinary diffusion. In this work, graphical methods were used for the estimation of diffusion coefficient of gases in highly-viscous oil-sands bitumens from isothermal, pressure-decay measurements. The approach involves modeling the rate of change in pressure with the diffusion equation for the liquid phase coupled with a mass balance equation for the gas phase. The inverse solution framework is utilized to arrive at graphical techniques for estimating the diffusion coefficient. An advantage of the proposed techniques is that the diffusion coefficient is estimated directly, i.e. without making it an adjustable parameter. The novelty of the proposed method is in its simplicity as well as its ability to isolate portions of the pressure-decay data affected by experimental fluctuations. The diffusion coefficients of CO2, CH4, and N2 in Athabasca bitumen at 75–90˚C and about 4 MPa were estimated and compared with literature values.
Near a Kilometer of Perforating Guns, in a 7½ Kilometer, Extended Reach Well - Coiled Tubing Shows its Mettle in New Zealand
Authors: Bartholomew P. , Portman L. , Frost R. , Nunn P. , Vause P. , Edmondson D. , Andrich L. , LaGrange T. 
Published: December 2007

Abstract
This paper details a coiled tubing perforating campaign conducted in New Zealand, during the first half of 2006.
Coiled tubing has been used for deploying perforating guns for many years now. The challenge with this type of work, is first designing a coiled tubing string which can push and pull long gun lengths along highly deviated wells. Secondly, a method of retrieving (and deploying) the guns against a high wellhead pressure is required. In this instance, down hole isolation valves could not be used. Instead, a pressure deployment system was utilized.
The length of perforating guns run during this campaign is extreme, but not unique1. The use of pressure deployment systems is also not unique2. The combination of these factors along with the facts that this is a very remote operation (with regard to oilfield manufacturing and supply), that much specialized equipment needed to be fabricated (in a market cycle where all equipment deliveries see long lead times), and that the operation must take place in a seismically active area, all combine to make this a very challenging project.
This paper lists observations taken from the project that may prove useful to future campaigns of a similar nature.
Significant Peculiarities Prediction of Condensate Production in Gas Condensate Fields
Authors: Brusilovsky Alexander I. , Nugayeva Alphiya N. 
Published: December 2007

Abstract
The paper is devoted to the prediction of the condensate content in a gas-condensate mixture during depletion, and the estimation of the condensate recovery factor. It is shown that the traditional approach to tackle this problem may result in both overestimated and considerably underestimated condensate production forecast.
Individual and combined influence of the formation temperature and dispersed hydrocarbon (HC) liquid on the variation of the C5+ content in the reservoir gas, and the condensate recovery factor for the depletion of the condensate gas cap are analyzed with examples of the Orenburg and Dulisma fields. It is proved that the traditional approach to predicting the presence of C5+ group in the formation gas by ignoring the presence of the dispersed hydrocarbon liquid (DHCL) in the reservoir can lead to overestimated condensate production rates. Particular influence of the anomalous low formation temperature on the retrograde condensation rate and the associated condensate recovery factor are analized.
Advanced methods for modeling multicomponent phase behavior are used to analyze the impact of the HC fluids properties on the expected C5+ content in the produced mixture, and on the condensate recovery factor for the depletion of near critical gas condensate reservoirs. It is shown that when dealing with such HC systems, the traditional approach to predicting the C5+ hydrocarbon content in the produced gas, based on differential condensation (constant volume depletion, CVD) studies, may result in significantly underestimated condensate production, and consequently its recovery factor.
A Novel Cased Hole Density-Neutron Log–Characteristics and Interpretation
Authors: Elkington P. A. S. , Pereira C. A. , Samworth J. R. 
Published: December 2007

Abstract
We have characterized the response of a compact 2¼-inch (57mm) diameter open-hole formation density logging tool for cased hole environments. Data are processed with an established open hole transform in which the casing effect appears as a simple attenuation term in the count rate domain, and variations in cement thickness are compensated using a classical dual-detector spine-and-ribs approach applied in the density domain. The combination of through-casing density and casing-corrected neutron porosity has been applied to the evaluation of by-passed pay and shallow gas, and to the evaluation of wells where open hole acquisition has not been feasible for operational, hole quality, or economic reasons. The tool-specific neutron porosity excavation effect has been characterized for gas-bearing sands.
Case history and model results suggest accurate formation densities are achievable for casing thicknesses up to about 0.35 inches (9mm) if cement is less than about 1 inch (25mm) thick, albeit with loss of precision relative to open hole. Formation sensitivity declines with increased cement thickness until practically all is lost for casing standoffs in excess of 1.5 inches (38mm). For modest thicknesses, however, cased hole density-neutron gas evaluation has advantages relative to the neutron-dipole sonic method; in particular it does not rely on good cement bond, it has generally superior spatial resolution, and (optionally) data can be acquired in memory mode on slickline in operating environments that do not favour conventional wireline units.