bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Trial of Multiphase Metering Systems in Light Oil Steam Flood Applications, Minas - Indonesia
Authors: Uphold Donald D. , Siboro Paulus D. , Kouba Gene E. 
Published: December 2007

Abstract
This paper illustrates performance and best practice of compact multiphase metering systems that have been operating for 2-years in the light-oil steamflood pilot in Minas-Sumatra. These results motivate the need for life-cycle risk models integrating new technologies to meet customer needs. In some cases, low-cost new-technology may not be the best choice. If multiphase metering systems are suitable, then a unified systems' vendor should be included on the team during all phases of the project, especially early on to support quality assurance during integration of sub-systems, and later during commission and operation to support quality control of the complete metering package. In this paper, we present two similar types metering systems for two different types of applications: 1) well-test measurement, and 2) bulk production measurement. Both metering systems are of the partial separation type and use a compact gas-liquid cylindrical cyclone separator, or GLCC© (copyright by The University of Tulsa, 1994). When constructed these were the largest GLCCs and are still believed to be the largest operating GLCCs in the world. After the produced fluids are separated into individual gas and liquid streams, each stream is volumetrically metered and then recombined. The liquid level in the separator is controlled by an innovative gas-liquid dual-mode control scheme. For water-cut measurement, the well-test system uses an on-line instrument whereas the bulk metering system uses a physical fluid measurement based on sampling and analyses. Field data and suggested modifications to achieve suitable operation are presented. In particular, we focus on the impact and uncertainty of higher than expected sand concentration, watercut, flowrate, pressure & temperature on the original design, and consequently discuss the specific changes we made to address these challenges.
Understanding Reserves Uncertainties in a Mature Field by Reservoir Modelling
Authors: Verbruggen Rini , Pannett Stephen , Stone Greg 
Published: December 2007

Abstract
The Maui C Sands reservoir contains most of the remaining gas-condensate reserves in the mature Maui Field. Technical and commercial management of a hydrocarbon producing field such as Maui relies heavily on the confidence in the forecasted production and reservoir performance and the associated uncertainties. This paper discusses how the key static and dynamic uncertainties can be identified, evaluated, and modelled to determine their impact on remaining reserves and further development options. The approach is based on the use of a combination of representative sector and full field dynamic models to establish the model sensitivities. A few models covering the range of uncertainties are then history matched in an iterative process whereby the uncertainty ranges are updated based on the history match results. Finally, production forecasts are generated for the history matched models to assess the range of reserves and to evaluate and optimise further development options. As a precursor to this, a single base case model is history matched and production forecasted whereby a statistical method is used to select the base case parameters and to assess the associated reserves uncertainty range.
Decision-Making with Incomplete Evidence
Authors: Fletcher Alistair , Davis John P 
Published: December 2007

Abstract
The aim of the paper is to highlight the challenges in making decisions when there is incomplete evidence and information. By understanding the challenges, businesses should be able to make faster, higher quality, decisions. This paper proposes methodologies incorporating probabilistic and other knowledge management techniques to assist in decision making under these conditions. A wide variety of models are generally used to help in the decision making process. With reference to the parameters and structure of a model, four basic types can be identified depending on the degrees of vagueness and completeness.
Type 1 models are deterministic and characteristic of much hard science and engineering. Type 2 models allow for inputs known only as distributions. These models are probabilistic and the basis of probabilistic reserves assessment, probabilistic risk analysis and many economic models. Type 3 models are characterised by vagueness in the overall structure and with input parameters expressible only as ranges and limits. Techniques such as imprecise probabilities (fuzzy logic's and Interval Probability Theory) have recently been developed to handle these models. Type 4 models are characteristic of many complex situations where actions in the future and / or issues of relevance and completeness are central. In other contexts such problems have been referred to as "messy" or "wicked". Many of the problems concerning project evaluations are Type 3 and Type 4, as are most problems that include elements of human judgement, interpretation and choice.
We describe a methodology and mathematics to address Type 3 & 4 problems based on hierarchical process modelling, recording of attributes and a calculus that combines incomplete evidence. We discuss the modelling, philosophy and mathematics that allows explicit incorporation of vagueness and incompleteness. Our approach is illustrated through case studies, including gas to liquid (GTL) investment decisions, prospect evaluation and carbon dioxide sequestration options.
The Griffin Development – Flying High on Infill Success
Authors: Workman L. J. , Slate T. V. , Oke B. F. 
Published: December 2007

AbstractIn recent years the successful drilling, completion and tie-back of three Griffin area infill wells and a re-entry campaign has resulted in improved production rates and increased reserves.The Griffin Area Development in the southern Carnarvon Basin, offshore Western Australia, consists of three oil fields; Griffin, Chinook and Scindian, tied to the "Griffin Venture" Floating Production Storage and Offloading (FPSO) facility. First production commenced in January 1994, with a maximum rate of 85,000 stb/d reached shortly after start-up.The Zeepaard Formation is the primary reservoir in the development. It has excellent productivity and strong aquifer support. In eight years of production, over 100 MMstb of oil has been recovered through nine vertical wells. Production began to decline from 1996, with escalating water cuts from the majority of the wells.Reprocessing of the 1991 3D seismic data, combined with reservoir modelling studies, led to the approval and subsequent drilling of two Zeepaard infill wells in mid 2000, one in the Scindian Field and the other in Griffin. The results of the Griffin infill well changed the understanding of reservoir sweep in that field and led to a re-entry campaign in late 2000. This was followed by a second infill well in early 2002.Each infill well has flowed in excess of 20,000 stb/d, lifting the production potential of the Griffin Venture, improving the reservoir sweep and accelerating reserves into field life. In February 2002, the facility was producing at 60,000 stb/d, with 40,000 stb/d of this attributable to the three infill wells drilled in the area since July 2000.
The Valuation and Strategy Setting for Remote Gas Reserves
Authors: van Elk Jan F. 
Published: December 2007

Abstract
With excess gas reserves available for development by LNG or feedstock projects, the international gas industry faces new challenges. The challenge for companies in the upstream sector of the industry is to maintain an optimised Gas Reserves Inventory based on the prognosis for the development of their gas markets. Gas exploration and maturation programs should be timed and selected according to the capacity of the markets to absorb their gas.
This is especially the case for Western Australia, where large gas reserves have been found and further exploration prospects are excellent, but market proximity is a key issue.
The decision to initiate gas exploration has to be made many years prior to the maturing of market opportunities and the requirement for reserves certification to support gas sales agreements.
An upstream gas supply venture is typically engaged in several marketing opportunities at the same time. Each of these has a discrete chance of successfully maturing into a gas sales purchase agreement (SPA). This paper explores and proposes a framework for analysing the relationship between a dynamic demand situation and the optimum Reserves Inventory. The method recognises the uncertainty in both the Reserves Inventory and in the prognosed Captured Market.
The concept of a Reserves Cover is introduced as the chance that the gas markets captured (as SPA's), within the reserves maturation timespan, can be supplied from reserves in a company Reserves Inventory. It is used to derive the optimal Reserves Inventory and the requirement and timing for growth of the Inventory through exploration.
The method allows a high level analysis of long term issues like the attractiveness of increasing the Reserves Inventory by gas exploration in the catchment area of the plant or gas scope maturation, and helps to determine the timing of the decision to approach other gas reserves holders.
The Integration of Intelligent Well Systems into Sandface Completions for Reservoir Inflow Control in Deepwater
Authors: Hill Leo E. , Izetti Renaldo , Ratterman Gene , Fonseca Sergio , Moreira Oswaldo , Ray Dan L. , McDonald Ken 
Published: December 2007

Abstract
This paper describes the application of the integration of intelligent well systems into sandface completions for reservoir inflow control in deepwater. In deepwater subsea applications, the ability to remotely control the inflow of water eliminates costly rig intervention while extending well life and increasing recoverable reserves. In deepwater Brazil, open-hole horizontal gravel pack completions with mechanical open-hole isolation have been integrated with proven all electric intelligent well systems. The planning, testing and implementation of these technologies will be detailed in this paper.
Deepwater Brazil continues to be a region where the need to improve economic performance in deepwater drives the implementation of new technologies. Horizontal gravel pack completions were implemented into deepwater subsea Brazil in 1998. To date, over 52 successful subsea horizontal gravel packs have been implemented for both production and injection wells. To further improving the economics of operating in deepwater, implementation of Level 5 Multilateral wells in the Campos Basin was initiated in 1999. As the success of open-hole horizontal gravel packing continued to show economic benefit, it was necessary to provide positive zonal isolation in conjunction with gravel packing. Application of diverter valve technology to achieve zonal isolation was successfully implemented in 5 subsea wells in the Campos Basin during the year 2001. The zonal isolation and long reach of horizontal wells provides the operator the ability to selectively drain a reservoir and achieve the lowest development cost per barrel oil equivalent (BOE).
The fully electric intelligent well system consisting of 3-1/2" and 5-1/2" inflow control devices was deployed on land in the Mossoro Field. The purpose of the installation was to prove the technology before transferring the application into subsea wells. These valves were operated remotely from the office location. After months of successful actuation and data acquisition, the system was pulled and prepared for installation into a deepwater subsea well. During the land based well test, it was deemed necessary to modify the volumes of data stored. Software modifications were made to optimize the rate of data storage.
In order to integrate the Intelligent Well System into the sand control completion, a process of optimization was necessary to meet well construction and operational requirements. This process was inclusive of well path design to reach the targeted well location while controlling the dogleg severity to allow placement of the intelligent well system and completion design to achieve inflow control and minimize operational risk during installation. This is the first application of an all electric remotely operated intelligent well system integrated into a sandface completion for the purpose of reservoir production management.
Multirate Test in Horizontal Wells
Authors: Merzouk Khelifa , Tiab Djebbar , Escobar Freddy H. 
Published: December 2007

Abstract
During a pressure drawdown test, it is quite difficult to hold a constant rate long enough to achieve the test requirements, especially for horizontal wells. Any change in rate, if not taken into account, can lead to erroneous results. Furthermore, pressure drawdown tests are not suitable in sand producing wells. Pressure buildup tests, in high production wells, are uneconomical because of income loss. For gas wells, it is impossible to determine both the coefficients of turbulence and the skin factor from a single constant rate test. For these reasons, a Multi-Rate test should be run instead of buildup or constant rate drawdown tests.
A method is presented to analyze variable rate tests for oil reservoirs. In this study, it is proposed to plot first the pressure variation, Δp/Qn versus the flowing time, t, and in a Log-Log graph the principle of superposition is applied for each flow regime, taking into account the time interval of each flow period. This method is used to estimate the reservoir parameters such as the permeability and skin. The pressure derivative concept is introduced for interpreting multi-rate tests. Only two different parameters are needed from the graph, the slope and intercept. The slope is used to estimate the permeability, and the intercept yields the skin factor.
The proposed technique is applicable for the interpretation of either continuously changing flow rate tests or a series of constant rate tests. This technique is illustrated by several numerical field examples for oil reservoirs.
Hydrocarbon Reservoir Detection Using Acoustic / Seismic Spectroscopy Method
Authors: Barzandji O. H. , Singer J. M. , Rodel E. D. , Leu W. , Plunkett J. , Ghirlanda F. , Akrawi K. 
Published: December 2007

Abstract
The seismic signal of the earth in the frequency range 0.1–20 Hz is recorded continuously from the surface using ultrasensitive velocity sensors. Hydrocarbon reservoirs are characterised by a unique spectral signature present in the frequency range 1–6 Hz. This signature diminishes at the rim of the reservoir and is absent at non-reservoir locations.
The results of our experiments are remarkably uniform for a great number of major oil producing areas worldwide, regardless if producing or virgin reservoirs are examined. Phenomenologically and structurally, the observed signals are similar to previously documented tremor signals ("continuous narrow band ground motion") originating, for example, from volcanoes and glaciers ("fluid-induced tremor"). Numerous continuous seismic signals exist which are usually rather weak and are often considered as useless background noise only. However, this "noise" also carries useful information, which is identified through inherent characteristics, such as the frequency spectrum, statistical properties or non-linear behaviour. It contains a spectral signature characteristic of the media or environment that it has passed through. Some such broadband background noise of the earth is present at every location around the world. The correlation between the output of the acoustic / seismic spectroscopy method and the net pay zone thickness can be calibrated at existing exploration or production wells. Moreover, a spatial mapping of our indicator allows a localisation of the potential oil/water contact and, indirectly, detection of faults and facies boundaries. The seismic spectroscopy method presented here can be used as an easy to apply and environmentally safe method for the detection of hydrocarbon reservoirs as well as for hydrocarbon field development and production monitoring.
Reservoir Modelling With Neural Networks And Geostatistics: A Case Study From The Lower Tertiary Of The Shengli Oilfield, East China
Authors: Wang L. , Tyson S. , Song X. , Cao H. , Wong P. M. 
Published: December 2007

Abstract
This paper demonstrates a case study of a hybrid methodology based on the combination of radial basis function neural network and sequential Gaussian simulation. The methodology is demonstrated with an application to modelling the porosity distribution in an oil reservoir of the Lower Tertiary in the north of Dongying depression, Shengli Oilfield, East China. The methodology first uses radial basis function neural networks to estimate the porosity trends (fluvial directions) from high-dimensional data system with both well and seismic data. Gaussian simulation helps to do the local uncertainty analysis for the reservoir model. The final results from the hybrid methodology assure our confidence on the reservoir model both horizontally and vertically. They are realistic and honour the geological rules of the oilfield. The technique is fast and straightforward, and provides an effective computational framework for conditional simulation.
Comparison of Predictions from Reservoir Models to Actual Production Data: Field Examples
Authors: Ezekwe John N. 
Published: December 2007

Abstract
Reservoir models were constructed on two gas condensate reservoirs (M-4/M4-A and M-6) in the Gulf of Mexico. The gas reservoirs are at a depth of 15000 feet subsea, over pressured and supported by active aquifers. Initial gas production was essentially water-free with steep pressure decline that was later followed by rapid rise in water production. Peak gas production from either reservoir reached about 166 MMCFPD.
The reservoir models were fully compositional. The models were history-matched with production data and then used to predict future performance. This paper compares predictions of the models to actual reservoir production data. The model for the M-6 reservoir predicted gas production with an accuracy of −0.72%, condensate production at +2.80% and water production at +12.4%. The predicted accuracies for the M-4/4A reservoirs are as follows: gas (-0.33%), condensate (−4.99%) and water (+25.56%).
The main objective of this paper is to provide data on the errors associated with the use of history matched models to forecast reservoir performance. Surveys of the petroleum literature indicate that they are few technical papers that compare model predictions to actual reservoir performance data over an extended period of time. Mass publications of these types of results are essential in establishing reservoir simulation as a valuable analytical tool for reservoir engineers. It will also improve its acceptance in the petroleum industry as a reliable tool for prediction of reservoir performance.
Predicting Critical Borehole Pressure and Critical Reservoir Pore Pressure in Pressure Depleted and Repressurized Reservoirs
Authors: Rhett D. W. , Risnes R. 
Published: December 2007

Abstract
Borehole instability, sand production, and completion failures during production and pore pressure depletion continue to be significant problems confronting the petroleum industry. This study develops quantitative models for predicting borehole shear failure in pressure-depleted and repressurized reservoirs by incorporating stress path into equations for shear of borehole wall rock. Critical reservoir pore pressure (CRPP) is defined as the pore pressure below which any drawdown or additional pore pressure depletion will result in the onset of borehole shear failure. Critical reservoir pore pressure and critical borehole pressure (CBHP) are defined in terms of initial stress state, initial reservoir pore pressure, the two horizontal principal stress paths, and commonly used failure criteria. The model includes both overbalanced (drilling) and underbalanced (production) scenarios. The model is applicable to both vertical and horizontal wells.
Field Application of a Novel Core-Based In-Situ Stress Estimation Technique
Authors: Pestman B. J. , Holt R. M. , Kenter C. J. , van Munster J. G. 
Published: December 2007

Abstract
In this paper, we present the first field application of a novel method to estimate in-situ rock stress. This technique, which we have baptized "PKM (Pestman-Kenter-vanMunster) method", uses Acoustic Emission-controlled polyaxial reloading of core in the laboratory. The method works analogous to the Kaiser effect that is observed when reloading along a single stress axis. Contrary to other Acoustic Emission methods, our novel approach is likely to measure present-day stresses, even if the core has been subjected to paleo-stresses that are higher than the present day stresses1. Proof of concept of the method has been provided using extensive experimental work on outcrop sandstone2 (which was subjected to a stress path simulating burial, coring and core retrieval to surface), a simple analytic model3 and numerical simulations using a 3D discrete particle method4.
Recently, the method was applied for the first time on real core material, a preserved sandstone core from the Munnekezijl field (onshore gas) of NAM (Nederlandsche Aardolie Maatschappij) in The Netherlands. An advantage of first application of the technique to this field was that there was availability of good quality stress estimates (for the same layer as where our core was taken) obtained from other methods. A study including hydraulic frac data and borehole breakout shape had been performed in the past to estimate the magnitudes of the major and minor horizontal effective stress. Hence, the results of our method could be compared to other good quality data.
Three samples have been cut from core taken at a depth of some 4000 m [13000 ft] in the Munnekezijl field, for application of our PKM method. Only the weakest sample showed a clear stress memory effect, and was used for stress estimation using our method. The results compared very satisfactorily with the estimates from the hydraulic frac data and borehole breakout analysis. Although this is only the first application, and further validation is needed, these results show a clear promise of the PKM method.
Improved Determination of Stress-Dependent Permeability for Anisotropic Formations
Authors: Bai M. , Meng F. , Roegiers J. -C. , Green S. 
Published: December 2007

Abstract
Qualitative determination of formation permeability is often obtained through laboratory flow tests on core plugs. However, the experimental determination of the permeability for anisotropic plugs (particularly the horizontal permeability) is difficult and less than perfect; generally relying on a highly simplified Darcy flow analysis. Numerical analyses could greatly improve the resolution, reduce the testing costs, and allow parametric investigations using sophisticated 3-D formulations. This paper reports such an analysis that interprets the analytical Darcy flow-pressure measurements, using numerical results to provide a "geometric factor". A numerical iterative procedure correlates the core plug measured flow and pressures at the inlet and outlet boundaries for different boundary sources to derive the core plug anisotropic permeabilities. Since stress changes generally influence permeability, a conceptual model is developed—again via an iterative numerical method—that accounts for the effects of the solid deformations. From this, numerical schemes have been developed using "equivalent geometric factors" with embedded mechanisms for modifying core plug permeability based on the changes in the solid strains that simulate the coupled flow-deformation behavior of selected reservoir rocks. This is the first detailed 3-D numerical analysis iterative scheme that practically allows realistic determination of permeabilities in anisotropic core plugs.