bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Semianalytical Thermal Multiphase Wellbore-Flow Model for Use in Reservoir Simulation
Authors: Livescu S.. , Durlofsky L.J.. J. , Aziz K.. 
Published: June 2010

Summary
The detailed interactions between the reservoir and the wellbore are especially important in thermal processes such as steamflooding and in-situ upgrading. These linkages, therefore, must be captured in thermal simulations. Although fully coupled thermal wellbore-/reservoir-flow simulators have been developed, the implementation of the thermal well model is somewhat complicated, and the simulations are computationally demanding. In this paper, we present a semianalytical treatment that enables the extension of existing isothermal wellbore-flow models to the nonisothermal case. The procedure entails the use of analytical solutions for wellbore temperature applied in conjunction with numerical solutions of the reservoir mass- and energy-balance equations coupled with wellbore mass- and momentum-balance equations. The approach thus enables a degree of decoupling between the wellbore flow and energy problems. We proceed by first presenting analytical solutions for wellbore temperature, developed under various assumptions (these basic solutions have been obtained previously). We then describe the use of one of these solutions, which allows for general variation of in-situ phase fraction and other properties along the wellbore, within the semianalytical context. The implementation of the overall method into a general purpose research simulator is also described. Results are presented for several cases involving multiphase flow in monobore and multilateral wells. Close agreement with reference solutions, obtained from a fully coupled thermal wellbore/reservoir model, is demonstrated for all of the examples. The semianalytical treatment is additionally shown to provide comparable or improved computational efficiency relative to the fully coupled model.
Valuing Oil and Gas Options by Least-Squares Monte Carlo Simulation
Authors: Willigers B. J. A. , Bratvold R. B. 
Published: June 2010

Summary
Least-squares Monte Carlo (LSM) simulation is a promising new technique for valuing real options that has received little or no attention in the oil and gas industry. In this paper, we will demonstrate how LSM simulation can handle more-realistic valuation situations including the ability to (1) handle more-realistic (probabilistic) price models and (2) deal with multiple, possibly correlated, uncertain variables.
The LSM method is applied here to an economics problem faced by many operators: What is the value of a gas field given the decision to trade the gas on the spot market as opposed to selling the gas through a long-term supply contract? A company that chooses to trade gas can decide when and how much to produce and can profit from changing market conditions, such as by increasing production during a high-price environment.
Three uncertainties have been modeled: the gas price, the operational costs, and the rate of production decline. Increasing profitability associated with rising hydrocarbon prices typically is offset partially by increasing expenditures. Hence, the costs have been correlated with the gas price. The expectation of the remaining reserves is adjusted continuously on the basis of the performance of the field. The latter is simulated by stochastically modeling the rate of production decline.
The paper shows that a gas field that can be produced and abandoned at will has a large value of flexibility. The net present value (NPV) of such an asset will underestimate the true economic value. A further benefit of using the real-option-valuation (ROV) approach discussed here is that the valuation procedure produces a strategy map showing actions within the project, not just numbers.
Detecting Thief Zones in Carbonate Reservoirs by Integrating Borehole Images With Dynamic Measurements: Case Study From the Mauddud Reservoir, North Kuwait
Authors: Li Bingjian , Najeh Hamad , Lantz Jim , Rampurawala Mansoor Ali , Gok Ihsan , Al-Khabbaz Mohammed 
Published: June 2010

Summary
One of the key issues in creating a good reservoir model in carbonate reservoirs is identifying the horizontal permeability conduits—"thief zones"—if there are any. In the Sabriyah field in Kuwait, dynamic measurements showed evidence of thief zones in the Lower Cretaceous (Albian) Mauddud formation. Early water breakthrough has occurred in some wells. Previous studies indicated that it was very challenging to detect the thinly layered thief zones using conventional openhole logs. This paper describes a method of recognizing the different types of thief zones in the Mauddud carbonate reservoirs using high-resolution image logs with calibration from core and dynamic measurements and by integrating image logs with nuclear magnetic resonance (NMR) and conventional openhole logs.
The Mauddud carbonates are Early Albian in age and consist of grainstones, wackstones, and mudstones deposited in a ramp setting. Observations from production logging tools (PLTs) and production data indicated that there are a few thief zones in different levels within the vertical Mauddud sequence. A previous core study shows that the fractures in the Mauddud formation are short (&lt;10 cm) and concentrated in diagenetically cemented layers. The fractured thin layers are believed to be the principal type of thief zone. Another type of thief zone is associated with better-developed vuggy porosity. This study shows that both fractured and vuggy porosity-related types of thief zones can potentially be detected through integration of high-resolution image logs with PLT, NMR, and conventional logs. In addition, methods of estimating fracture permeability and porosity-related permeability based on logs are also proposed. The log-estimated permeability determined using this approach fits better with the production profile and can then be used to evaluate the thief zones in a more quantitative manner.
Completion Design for Sandface Monitoring of Subsea Wells
Authors: MacKay S. , Lovell J. , Patel D. , Cens F. , Escanero S. 
Published: June 2010

Summary
The expense of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity, drainage, and flow assurance. For those wells requiring sand control, an additional constraint is that sandface sensors must be deployed on a separate completion run. The objective of a recent engineering development program was to create a new deployment system that addressed these constraints directly. Instead of individual gauges on mandrels, digital sensors were miniaturized and distributed along a single spoolable bridle. In addition, a novel inductive coupling mechanism was developed to pass power and data from the upper to the lower completion. In a recent subsea deployment in southeast Asia, such a coupler was attached to the top of a sensor bridle and both were deployed as part of an openhole gravel-pack completion. Standard packers and gravel-pack service tools were used. The system became activated when a mating inductive coupler was landed as part of the upper completion. Surface indication of landing was provided by incorporating mechanical feedback into the lower assembly. With the coupler components in position, the tubing hanger was landed into the horizontal tree. Upon activation of the electrical penetrator, high-resolution temperature data were then immediately available across the length of the sandface, which was an industry first for a subsea producing well. No additional penetrations were required in the tree.
Development of this system required coordination from the operator because of the multiple vendors involved in the project. They supervised multiple qualification and system-integration tests performed over the 2-year development period to ensure ultimate success in the subsea deployment.
Field results showed that the mating inductive couplers provided high-efficiency of power transmission so that industry-standard power settings were sufficient to power a bridle with one sensor per joint of screen. The sandface data were available onshore during the cleanup phase, allowing the operator to monitor the cleanup in real time. Once the wells are brought on line, the sandface data will further enhance the interpretation of flow allocation and reservoir drainage.
An Integrated Geomechanical and Passive Sand-Control Approach to Minimizing Sanding Risk From Openhole and Cased-and-Perforated Wells
Authors: Rahman Khalil , Khaksar Abbas , Kayes Toby 
Published: June 2010

Summary
The source of sand production is the presence of disintegrated sand grains caused by rock failure at the wellbore and/or perforation walls. Decision for appropriate sand-control strategy requires engineering analysis to evaluate timing and severity of sanding over the life of field conditions. Optimizing well parameters such as well trajectory, perforation orientation, and level of drawdown using geomechanical principles can minimize and delay sand production.
This paper presents a geomechanical modeling approach that integrates production history with information from drilling data, well logs, and rock-mechanics tests. A gas field in south Asia with 11 wells and several years of production experience is used to demonstrate this approach. Core-calibrated rock-strength-log profiles are estimated throughout the reservoir depth for all existing wells. A rock-failure criterion at the sandface is developed as a function of in-situ stresses, rock strength, well trajectory, perforation orientation, reservoir depletion, and drawdown. Sanding-evaluation results are calibrated and verified with production data and evidence of sanding in existing wells. Sand-free operating envelopes and sand evaluation logs are then generated for all existing wells and planned infill wells for the life of field conditions. Sand-prone zones and timing of sanding are established as a function of depletion and drawdown for each well, using production forecasts for the rest of field life. For new infill wells, optimum well trajectories, selective perforation intervals, and optimum perforation orientations are proposed to minimize and delay sand production. Recompletion and using passive sand-control methods including selective and orientated perforations are recommended for a number of existing wells.
This paper is expected to provide well engineers with guidelines to understand the principles and overall workflow involved in sand-production prediction and minimization of sand production risk by optimizing well trajectory, perforation orientation, and selective-perforation strategy.
A New Solution To Restore Productivity of Gas Wells With Condensate and Water Blocks
Authors: Bang Vishal , Pope Gary A. , Sharma Mukul M. , Baran Jimmie R. , Ahmadi Mohabbat 
Published: June 2010

Summary
During production from gas-condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dewpoint of the hydrocarbon fluid. Many of these gas reservoirs also have some water accumulation near the wells. This adds significantly to the total liquid blocking.
Experiments were conducted using both outcrop sandstone and reservoir cores to measure the effect of liquid blocking on gas relative permeability. A chemical treatment was developed to reduce the damage caused by condensate and water blocking. The treatment is composed of a fluorinated material delivered in a unique and optimized glycol-alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral-wet and increases the gas relative permeability.
The increase in gas relative permeability was quantified by comparing the gas relative permeabilities before and after treatment. Improvements in the gas relative permeability by a factor of approximately two were observed. The alteration of wettability after the chemical treatment was evaluated by measuring the USBM wettability index of treated reservoir cores. Measurements show that a significant amount of the surfactant is adsorbed on the rock surface, which is important for the durability of the treatment.
Many attempts have been made to develop effective chemical treatments to mitigate the damage caused by condensate and/or water blocking with little success until now under realistic reservoir conditions. Using inexpensive, safe, and effective solvents was one of the keys to the success of our new approach. Other researchers have mostly tried reactive materials that are subject to complications in downhole applications. We use a nonreactive, nonionic polymeric surfactant that has none of these problems and is robust across a wide range of temperature, pressure, permeability, and brine salinity.
We have developed a chemical treatment for liquid blocking that shows great potential to increase production from gas-condensate wells. Compositional simulations indicate that the economics of this treatment process is likely to be very favorable.
SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmount
Authors: Handfield T.C. , Nations T. , Noonan S.G. 
Published: June 2010

Abstract
Gas lift completions for steam-assisted gravity-drainage (SAGD)(1) producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used because of the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole through open-ended tubing or nozzles, which if not properly sized can result in operational issues such as fluid/gas slugging and pressure instabilities that negatively impact the overall lift efficiency.
In 2006, ConocoPhillips conducted a study to design a gas lift system for the Surmont SAGD development that would allow better control of lift gas into the production string. In late 2007, the wells completed with gas lift were placed on production. This paper covers the data-collection effort and analysis completed to determine the efficiency of the two types of gas lift nozzles used in the completions, the methodology for optimization of SAGD gas-lift systems, and recommendations for future improvement.

Background
Surmont, an in-situ oil-sands project, is located approximately 60 km southeast of Fort McMurray in the Athabasca oil sands (Figure 1). This multiphase SAGD project is a 50:50 joint venture between ConocoPhillips Canada Ltd. (CPC) and Total E&P Canada Ltd., with CPC as the operator. The Surmont pilot began injection of steam in 1997. The pilot comprises three SAGD well pairs that use a variety of artificial-lift methods. These wells have been tested to determine the preferred method of artificial lift for the first commercial phase.
Steam injection, for Phase 1A of the commercial development, was initiated in mid-2007. Conversion to full SAGD production followed in late 2007. Phase 1A comprises 20 well pairs in which all the producers have been completed to produce through gas lift for the initial life of the well. Phase 1 (A, B, and C) has a capacity of 3,975 m3/d (25,000 B/D) and is expected to reach peak production in 2012. A second phase is slated for commercial startup before the middle of the next decade. Upon completion and full ramp-up, it is estimated to bring peak production from both phases to 15,899 m3/d (100,000 B/D). Additional phases at Surmont are also under study.
PRISE Validates Resource Triangle Concept
Authors: Martin S.O.. O. , Holditch S.A.. A. , Ayers W.B.. B. , McVay D.A.. A. 
Published: June 2010

Summary
As conventional gas (CG) resources are depleted, unconventional gas (UG) resources (gas from tight sands, coalbeds, and shale) are becoming increasingly important to US and world energy supply. The volume of UG resources is generally unknown in most basins outside North America. However, in many mature North American basins, UG resources have been produced for decades, and resources and reserves are well characterized. The objective of this work was to determine the quantitative relations between known conventional and unconventional hydrocarbon resources in mature North American basins, with the ultimate goal of using these relations to estimate UG resources in frontier basins outside North America.
We used assessments by the US Geological Survey (USGS), Potential Gas Committee (PGC), Energy Information Administration (EIA), National Petroleum Council (NPC), and Gas Technology Institute (GTI) to evaluate relations among hydrocarbon-resource types in the Appalachian, Black Warrior, Greater Green River, Illinois, San Juan, Uinta-Piceance, and Wind River basins. We chose these seven basins for initial analysis of relations between CG and UG resources because they are mature basins for both conventional and unconventional oil and gas production. To conduct this analysis, we wrote a computer program that we call Petroleum Resources Investigation Summary and Evaluation (PRISE). Input data for PRISE, obtained from published data sources and resource assessments, were values of technically recoverable resources, consisting of the following resource categories: (1) cumulative production, (2) proved reserves, (3) probable and possible reserves and contingent resources (PPC), and (4) prospective resources. We then analyzed these data in each of the seven basins to assess the relationship between conventional- and unconventional-resource volumes.
For the seven basins studied, we found that approximately 10-20% of the total recoverable hydrocarbon resources are conventional oil (CO) and CG, whereas 80-90% of the recoverable hydrocarbons are UG resources. We suggest that the results of this study may be used to estimate recoverable resources from UG reservoirs in frontier basins worldwide, where CO and CG resources are known but UG resources have not been evaluated.
Uncertainty Quantification in Reservoir Performance Using Distances and Kernel Methods—Application to a West Africa Deepwater Turbidite Reservoir
Authors: Scheidt Céline , Caers Jef 
Published: June 2010

SummaryStochastic simulation allows generating multiple reservoir models that can be used to characterize reservoir uncertainty. In many practical situations, the large computation time needed for flow simulation does not allow an evaluation of flow on all reservoir models. In this paper, we propose a method to select a subset of reservoir models reflecting the same uncertainty in flow response as the full set. Using the concept of distance, we map the reservoir models to a low-dimensional space where kernel clustering is applied to identify a subset of representative reservoir models of the entire set. Flow simulation and subsequently uncertainty quantification are performed on this subset. A case study is presented of an architecturally complex deepwater turbidite offshore reservoir with large uncertainty in the type of depositional system present.
Experimental Study of Electrical Properties of Oil-Based Mud in the Frequency Range From 1 to 100 MHz
Authors: Patil Parimal A. , Gorek Matthias , Folberth Martin , Hartmann Andreas , Forgang Stan , Fulda Christian , Reinicke Kurt M. 
Published: June 2010

Summary
Formation-resistivity measurements in boreholes require accurate knowledge about the electrical properties of drilling fluid to exclude any measurement misinterpretations. For many drilling applications, oil-based mud is the preferred drilling fluid because of properties that include excellent shale stability, corrosion inhibition, lubricity, reusability, resistance to contamination, and higher rate of penetration. Although the electrical resistivity of oil-based mud is generally high, it depends on many parameters. We studied electrical resistivity and dielectric permittivity of oil-based muds as a function of frequency and temperature with varying oil and salt content and varying oil/water ratio. Measurements were performed by use of a coaxial test fixture and an impedance analyzer. The accuracy of the measurement system has been determined using standard materials such as air, deionized (DI) water, methanol, n- butanol, and n-octanol. The analysis shows that published models dealing with electrical properties of rocks can be compared well with those of oil-based muds. Resistivity and relative permittivity decrease with increasing temperature and frequency. No clear relationship is revealed between resistivity and water content, but relative dielectric permittivity does depend on water content of oil-based muds. Oil and salt content are of secondary importance. The study shows that the relative dielectric permittivity is related exponentially to the oil/water ratio of oil-based muds, which provides a means of estimating dielectric permittivity of oil-based mud if the oil/water ratio is known.
Control Requirements for Automatic Managed Pressure Drilling System
Authors: Godhavn John-Morten 
Published: June 2010

Summary
Automatic control solutions for drilling are expected to become widely used in the future. Both basic and more advanced control tools are well established in other communities such as offshore processing facilities and oil refineries. Drilling systems, however, have traditionally been operated manually. There is a great economic potential for the introduction of automatic control providing reduced drilling time, increased regularity, and improved performance, especially for wells with very narrow pressure margins. One example of automated drilling is automatic control of the downhole pressure by topside choking in managed-pressure-drilling (MPD) operations. Narrow drilling margins, especially in depleted reservoirs, ask for highly accurate pressure control.
Statoil applied automatic MPD successfully offshore at the Kvitebjørn field in the North Sea in 2007. This paper presents some MPD results from Kvitebjøm and discusses automatic control requirements for drilling operations. The requirements for MPD operations include a specified accuracy for a set of normal operations, such as rate changes and set point ramping during connections, surge and swab, and some failure operations, such as power loss, gas kicks, and blocked choke. The paper also includes some ideas for the future of intelligent-drilling operations with increasing automation.