bluuebunny/crossref_metadata_2025_split huggingface dataset:
Another Look at Layered Prospects
Authors: Murtha J. A. , Peterson S. K. 
Published: December 2007

Abstract
Often a drilling prospect has multiple horizons, each with its chance of success and its volumetric estimate of reserves. A proper evaluation of these prospects acknowledges the multiplicity of possible outcomes, ranging from total failure to total success. If the layers are independent, it is simple to assign probabilities to these outcomes. Whether one seeks a simple mean value or a more sophisticated Monte Carlo simulation, the independence assumption gives a straightforward procedure for estimating aggregate reserves.
When the layers are dependent, however, the aggregation problem becomes more subtle: the success or failure of one layer alters the chance of success of other layers, and the corresponding probabilities of the various combinations of successes are more difficult to calculate. Moreover, the rules of conditional probability, notably consequences of Bayes’ Theorem, provide challenges to those who assign estimates for the revised values. Even in the case of two layers, some estimators incorrectly assign these values by failing to quantify correctly their interdependence. These issues were addressed by Murtha1, in which a method was proposed to overcome the pitfalls of conditional probability. Then, at the SPE 2000 ATCE, Delfiner2 and Stabell3 offered alternative procedures for handling dependence.
We propose a new Monte Carlo simulation method, which is simple to describe for two layers, is based on tested concepts, can be shown to yield desired conditional probabilities, readily extends to any number of layers, and, most importantly, always honors Bayes’ Theorem.
As in the earlier paper1, the generic form of this model can be applied to prospects in adjoining fault blocks, step-outs, and other forms of multiple targets that should be regarded as a package when ranking prospects.
A Portfolio Management Approach to Assessing Acquisition and Divestiture Candidates
Authors: Allan Paul D. 
Published: December 2007

Abstract
The trend towards consolidation in the E&P sector has resulted in significant opportunities for smaller companies to acquire the non-strategic assets of larger companies as portfolios are rebalanced and assets are rationalized. Properties or prospects viewed as non-core or materially insignificant to the majors may have the potential to significantly impact the portfolio of an independent. This paper outlines a specific approach to evaluating acquisitions and divestitures in terms of portfolio value and risk management. Case studies are used to demonstrate how portfolio management can assist a company in appropriately evaluating an asset by quantifying the impact an asset has on the company's ability to meet its targets. The concept of portfolio value as opposed to deal value is described in an effort to demonstrate the interactions between project selection and targets within a portfolio. The examples will demonstrate the benefits of a portfolio management approach, particularly when dealing with the complexity of multiple projects, timing variability, market risks, and variability in asset performance.
Direct Experiments on the Ocean Disposal of Fossil Fuel CO2
Authors: Brewer Peter G. , Peltzer Edward T. , Orr Franklin M. 
Published: December 2007

Abstract
Substantial progress has been made in carrying out small-scale field experiments to investigate the scientific basis for disposal of CO2 that results from burning of fossil fuels in the deep ocean. A remotely operated vehicle (ROV) was used to carry liter quantities of CO2 to depths from 250 to 3650 m in the ocean and to release the CO2 in a controlled manner. A video imaging system allowed observation of the behavior of the CO2 released. CO2 released at intermediate depths forms bubbles that rise. Below about 2750 m liquid CO2 is more dense than sea water, and CO2 released at greater depths descends further. Hydrate formation was observed for depths below about 350 m. We show through video imagery, direct measurement, and model calculations that the dissolution rate of liquid CO2 in the deep ocean is 3 pmoles/cm2/sec. The slow dissolution rate limits the local concentration of CO2. Limited observations of the approach of marine life to CO2 released on the sea floor showed no apparent avoidance reactions.
Multiphase Flowmeters in Well Testing Applications
Authors: Theuveny B. C. , Ségéral G. , Pinguet B. 
Published: December 2007

AbstractDual-energy spectral gamma ray / Venturi multiphase flowmeters present an efficient and cost-effective means of testing wells in many field applications. A simple, efficient and quick procedure optimizes the utilization of these types of multiphase flow meters for well testing. This paper presents the field operating procedures for installing and using multiphase flowmeter and gives practical recommendations for performing well tests with or without a reference, such as a separator. The analysis of 415 multiphase well tests performed worldwide has provided some insights into the accuracy achieved in the field and has led to some recommendations for the test design.The ability of a multiphase flowmeter to perform a measurement in the absence of a flowing reference is essential to well testing in most applications. Furthermore, the high mobility of the equipment (with up to three wells tested in three different locations per day) allows a very efficient and short turn around time for installation and operation.The parameters required to perform the setup of a meter fall into two categories: meter static empty pipe reference and fluid properties. A detailed review of each parameter is presented along with its sensitivities when determining the flow rates of oil, gas and water. A description of the field procedure used to determine each setup parameter is provided and a series of field examples are presented that illustrate the efficiency of using multiphase flowmeters for well testing.
Segregated Flow is the Governing Mechanism of Disproportionate Permeability Reduction in Water and Gas Shutoff
Authors: Stavland A. , Nilsson S. 
Published: December 2007

Abstract
This paper describes the mechanism for disproportionate permeability reduction (DPR). Recent papers have discussed possible DPR mechanisms. Most of the papers conclude that there is not yet a single factor that determines DPR. The intention of this paper is to clarify that there is a single model, which explains the observed DPR effects. This model relies on segregated flow of oil and water at pore level and on continuity in the oil phase at placement of the DPR fluid. With this model DPR is demonstrated for both gel and single polymer systems at different wettabilities. Oil continuity is normally easier to obtain for single polymers than for crosslinked gels. Gel systems may, however, be more robust. The paper describes a method for placement of water-soluble gel while maintaining open pathways for oil. Additionally, it is shown that using the phase permeability reduction ratio is not a good measure for defining optimum DPR. Therefore a new selectivity parameter is introduced which demonstrates to be more effective.
Production Analysis of Long-Term Linear Flow in Tight Gas Reservoirs: Case Histories
Authors: Arevalo-Villagran Jorge A. , Wattenbarger Robert. A. , Samaniego-Verduzco Fernando , Pham Tai T. 
Published: December 2007

Abstract
Actual field data show linear flow in a large number of tight gas wells. Sometimes this linear flow is transient for years. Linear flow is normally associated with hydraulic fractures. Short-term linear flow production analysis may characterize fracture treatments, but long-term linear flow production may be controlled in some cases by the reservoir geometry; in others, it is controlled by the natural occurring reservoir properties. In this paper, long-term linear flow caused by both the presence of natural parallel fractures and vertical flow in a high permeability streak is investigated. An analytical matrix-parallel fracture model for a single-phase flow is presented. A systematic procedure to analyze linear flow in tight gas wells is described. Application of this methodology to production analysis from several tight gas wells and validation of the results by using numerical simulation are also shown.
Field-Wide Variations of Trapped Gas saturation in Heterogeneous Sandstone Reservoirs
Authors: Hamon G. , Suzanne K. , Billiotte J. , Trocme V. 
Published: December 2007

Abstract
Maximum residual gas saturation (SgrM) is known to be a key factor to evaluate the gas recovery from a lean gas reservoir invaded by aquifer water. This work focuses on variations of SgrM within heterogeneous gas-bearing sandstone reservoirs. Our aim is to produce a reservoir model based on SgrM values consistent with petrophysical trends. Literature presents no SgrM values below 20 % and reported trends usually indicate that SgrM decreases as porosity increases.
Three hundred measurements of SgrM have been performed by liquid capillary imbibition at laboratory conditions on dry plugs. The following data are also available: lithological description, thin sections, XRD analysis, NMR measurements, porosity, permeability, grain density, formation factor and cementation factor. The core plugs are selected from two Far East and one West Africa sandstone gas reservoirs and from Fontainebleau Sandstone outcrops. Plug porosities and permeabilities, respectively range from 6 % to 25 % and from 0.1 to 3 000 mD, with clay content ranging from 0 to 33 %. The main results are:
SgrM values are very scattered from 5 % to 85 %. SgrM against porosity plots present three major trends: – Two very different but clear trends exist in the low to medium porosity range (below 14 %). As porosity decreases, SgrM increases for Fontainebleau sandstone whereas it decreases for other sandstones. – Concerning the highest porosity values, i.e. above 14 %, the two above mentioned trends merge to an average of around 25-35 %. No relationship exists between SgrM and either grain density, or formation factor, or cementation factor. The amount of clay controls the SgrM versus porosity relationship. SgrM decreases as the clay content increases. No relationship was found between the type of clay and SgrM. SgrM decreases as microporosity, as represented by the NMR Clay-Bound Water, increases. It suggests that microporosity does not trap gas.
The Optic Oil Field: Deployment and Application of Permanent In-well Fiber Optic Sensing Systems for Production and Reservoir Monitoring
Authors: Kragas Tor K. , Williams Brock A. , Myers Gregory A. 
Published: December 2007

Abstract
Development and exploitation of oil and gas resources in increasingly difficult operating environments such as deepwater raise many technical challenges. Among these is the ability to provide assurance on the completions and production from high-cost and complex wells. Real-time, permanent wellbore and reservoir monitoring is a critical technology for providing assurance and maximizing profitability of these fields.
Recent developments in fiber optic sensing technology have resulted in reliable alternatives to conventional electronic systems for permanent, downhole production and reservoir monitoring. In-well fiber optic sensors are now being developed and deployed in the field for measuring temperature, pressure, flow rate, fluid phase fraction, and seismic response. Bragg grating-based fiber optic systems combine a high level of reliability, accuracy, resolution and stability with the ability to multiplex sensors on a single fiber, enabling complex and multilateral wells to be fully instrumented with a single wellhead penetration. These systems are being installed worldwide in a variety of operating environments for a variety of applications.
This paper presents several recent deployments of in-well fiber optic monitoring systems, including descriptions of the downhole sensor assemblies, installations, and measured data. Installations of fiber optic pressure and temperature systems in a land well and in the Gulf of Mexico and an all-fiber flow and liquid fraction system in deepwater Gulf of Mexico are discussed. A general description of fiber optic sensing and Bragg grating-based sensing systems is also presented.
Active Feedback Control as the Solution to Severe Slugging
Authors: Havre Kjetil , Dalsmo Morten 
Published: December 2007

Abstract
Severe slugging in multiphase pipelines can cause serious and troublesome operational problems for downstream receiving production facilities. Recent results demonstrating the feasibility and the potential of applying dynamic feedback control to unstable multiphase flow like severe slugging and casing heading have been published (Refs. 4,9,1,5 and 2). This paper summarizes our findings on terrain-induced slug flow (Ref. 2). Results from field tests and as well as results from dynamic multiphase flow simulations are presented. The simulations were performed with the pipeline code OLGA2000.
The controllers applied to all of these cases aim to stabilize the flow conditions by applying feedback control rather than coping with the slug flow in the downstream processing unit. The results from simulations with feedback control show in all cases stable process conditions both at the pipeline inlet and outlet, whereas without control severe slug flow is experienced. Pipeline profile plots of liquid volume fraction through a typical slug flow cycle are compared against corresponding plots with feedback control applied. The comparison is used to justify internal stability of the pipeline. Feedback control enables in many cases a reduced pipeline inlet pressure, which again means increased production rate.
The paper summarizes the experience gained with active feedback control applied to severe slugging. Focus will be on extracting similarities and differences between the cases. The main contribution is to demonstrate that dynamic feedback control can be a solution to the severe slugging problem.
Crude Oil-Natural Gas Two-Phase Flow Pattern Transition Boundaries at High Pressure Conditions
Authors: Manabe R. , Zhang H.-Q. , Delle-Case E. , Brill J. P. 
Published: December 2007

Abstract
The effects of pressure on flow pattern transition boundaries for crude oil-natural gas two-phase flow were investigated.
Experimental observations of flow patterns were carried out for different pressures (200 and 450 psia) and inclination angles (horizontal, +1 degree and vertical). Special attention was given to the stratified-intermittent transition and the intermittent-annular transition for horizontal and inclined flow, and the transition to annular flow for vertical flow, since these boundaries were known to be sensitive to pressure.
The experimental results show that pressure affects the stratified-intermittent transition for horizontal flow and slightly affects the intermittent-annular transition for inclined flow and for vertical flow. The predictions of transition boundaries by existing mechanistic flow pattern prediction models show good agreement for all transition boundaries described above.
Use of Compositional Modelling in the Development Planning of Gbaran Field, Nigeria
Authors: Matemilola S. A. , Osaigbovo B. O. , Lin C. J. 
Published: December 2007

Abstract
Compositional simulation was applied in the development planning of Gbaran field in Nigeria. A major challenge of the study was to determine the optimal development and management strategy for maximising recovery of both oil and condensate, simultaneously. A full-field simulation model was constructed to accurately simulate the reservoir fluid phase behaviour, study the reservoir displacement and recovery mechanism and optimise the configuration and design of surface facilities. The reservoir fluid was adequately characterised using an 8-component Peng-Robinson equation-of-state model. The model was used to predict future reservoir performance under various developments and operating scenarios and to determine the optimum oil and condensate recoveries. The study showed that an integrated oil and condensate development strategy involving gas re-injection and partial cycling would lead to optimal oil and condensate recoveries of 63 % and 68 % respectively. Under natural depletion however, the recovery for oil would be 49 %, while condensate recovery would be relatively insignificant.
Moderate Velocity Flow in Fractures
Authors: Kløv T. , Skjetne E. , Gudmundsson J. S. 
Published: December 2007

Abstract
Moderate velocity pressure loss in rough fractures in Bentheimer sandstone was analyzed with theory for weak inertia flow in porous media. The pressure loss did not follow Darcy's law nor the Forchheimer equation. Instead the pressure loss is the sum of a linear term and a cubic term in velocity in accordance with a theory for weak inertia flow in porous media and fractures. The Darcy permeability in the linear term is given by a power law in fracture width with a power greater than two. Darcy permeability was modeled by tortuosity for a self-affine fracture and an effective fracture width normal to the flow path. The cubic weak inertia pressure loss is also a power law in fracture width, even though the geometry dependent factor is dimensionless. To the best of our knowledge this is the first experimental result showing that the weak inertia equation describes moderate velocity flow in natural fractures.
Integrating Permeabilities from NMR, Formation Tester, Well Test and Core Data
Authors: Haddad S. , Cribbs M. , Sagar R. , Tang Y. , Viro E. , Castelijins K. 
Published: December 2007

Abstract
Permeability is a critical reservoir parameter that defines well and reservoir performance. An accurate knowledge of permeability is critical to forecasting rates and designing production facilities. The permeability determined from different sources can vary significantly, resulting in inconsistent estimates of well and/or reservoir performance.
In this paper, permeability values and evaluation methods, are discussed and verified with field data. It is shown how NMR derived permeabilities calibrated to MDT or comprehensive core data can be used to define well/reservoir performance. By accounting for the effects of overburden, as well as, pore pressure when measuring permeability in core tests, more representative values of permeability can be determined. These values of permeability can be used to accurately calibrate NMR permeability data.
The simulation and calibration results are compared to measured well test data. Results from this work show that if these various sources are integrated properly an accurate well productivity model can be achieved.
Case Study: Maximizing Productivity with Extreme Underbalance Perforation
Authors: Potapieff Igor , Lallemant Francois , Rusly Albert , Zen Djati Wangsa , Retnanto Albertus , Kermoud Mohamed , Danardatu Heru , Murdiyono Murdiyono 
Published: December 2007

AbstractTunu field is the major gas supplier of the East Kalimantan system. It started producing in 1990 and more than 200 wells have been drilled to date. The field exported an average 1.3 bcf/d in 2000.In early 1999, extreme underbalance perforation (EUB) was introduced for monobore wells to reduce the skin effect to provide more flow capacity and maximize hydrocarbon recovery from the reservoir. The differential pressure between the wellbore and the formation creates a sufficient drawdown to instantaneously clean the perforated channels as soon as they are made. The challenge is to safely perforate under a drawdown of few 1000's psi instead of few 100's psi for classical perforations.The anchor + stackable perforating gun system has been evaluated and improved to permit EUB perforating to be performed safely. The heart of the EUB gun system is a mechanical release anchor that secures the guns firmly during perforation avoiding the risk of lifting the tool inside the wellbore. As there is no wireline cable while perforating, the well is flowing instantaneously allowing immediate clean up. Using this system, the underbalance is now limited only by: the drawdown on the formation (limited in case of depleted sand) and the potential risk to destabilize the formation and produce sand formation.So far, 20 jobs have been done safely on Tunu field with the differential pressure up to 4800 psi, without sand production. The paper will describe the operation procedures and the statistical approach (PBU results) demonstrating the benefit of EUB technique.For Tunu field, this perforation technique increases in average by 15% the initial productivity compared to classical perforations for a relatively low incremental cost.
An Automatic Production Monitoring System - Design and Applications
Authors: Chen Shing-Ming 
Published: December 2007

Abstract
Periodic field measurements and surveys often result in an abundance of data that needs to be analyzed to assist in optimizing the field production. Without a proper approach to managing and interpreting the data, valuable information that may be realized from the data can easily be overlooked.
This paper presents the design and application of an automatic production monitoring system that can be set up on a spreadsheet utilizing the spreadsheet's data operation and graphical capabilities. The program can be used as the ‘first pass’ screening tool to evaluate the production performance. Based on the historical production data incorporating the user-specified criteria, the current performance of each well is categorized as ‘normal', ‘damaged’ or ‘under-performed'. The potential production increases that may be realized by working over candidates in a typical oil field can also be estimated. With the innovative multi-scale plotting and field-wide mapping techniques, the program can provide the reservoir or production engineers with a gross scoping tool for a high-level overview of both individual well behavior and field-scale performance.
In this paper, the design considerations of the program, the advantages and disadvantages of its features, and field examples illustrating its applications are discussed.
World-Class Extended-Reach Drilling Performance in Abu Dhabi–A Case Study in How to Beat the Learning Curve
Authors: Al-Suwaidi Abdullah Saeed , El-Nashar Rady Ahmed , Allen Frank , Brandao Fernando J. 
Published: December 2007

Abstract
The Abu Dhabi Company for Onshore Oil Operations (ADCO) has a program of exploration and appraisal drilling from artificial islands in an environmentally sensitive shallow marine location. In early 2000, ADCO management set up a team to look at the feasibility of drilling extended-reach wells to reduce both the impact on the environment and the cost of drilling these wells.
This paper summarizes the work that has been done and the progress that has been made in delivering ADCO's first extended-reach well. It describes how the key risks to delivering the well were addressed and how a systematic approach to well planning contributed to the exceptional results. The modeling and simulation work performed in planning the well and preparing a comprehensive well program, and the use of real-time data to validate the models are detailed. The process adopted to ensure that every member of the team understood the program and was committed to the successful delivery of the well is also described.
The company is in the process of drilling the extended-reach well with a measured depth of 18,748 ft and a horizontal displacement of 13,780 ft. At the time of writing the horizontal section is being drilled. Well construction up to the completion of the pilot hole is covered in this paper.
When ADCO started to prepare for this well the company and the newly formed drilling team had limited experience of extended-reach drilling (ERD). However, progress on the well has been extraordinary. When the pilot hole reached target depth the well was 39 days ahead of the program. This drillingperformance is in the upper quartile of global land-based ERDwells (defined by industry analysts as better than 24.6 days per 10,000 feet drilled).