bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of Heavy Oil Fractured Carbonate Bati Raman Field: Evaluation of Steam Injection Potential and Improving Ongoing CO2 Injection
Authors: Babadagli T. , Sahin S. , Kalfa U. , Celebioglu D. , Karabakal U. , Topguder N. N. 
Published: September 2008

AbstractWith 1.85 MMM bbl OOIP, the Bati Raman field is the largest oil field in Turkey. After its discovery in 1961, the field was put on stream for primary production until 1986. The recovery factor was only 2% after twenty five year production mainly due to low oil gravity. The well-known immiscible CO2 flooding project commenced in 1986, and the recovery factor reached 5% at the end of 2007.The recent steady decline in production entails the implementation of new development plans and this paper summarizes these efforts. After reviewing the performance of the current CO2 injection, short and long term development strategies were discussed. Short term plans include the continuation of the CO2 project in the areas where it is still viable. Some parts of the field are under WAG process. To improve the recovery in the short run by a better sweep (or displacement), a chemically augmented water injection process was proposed in those areas. Potential chemicals (surfactants and alkalis) were tested for wettability alteration and IFT reduction applying static (spontaneous) imbibition experiments. The best performing chemicals were determined for the field pilot after an economic analysis. In addition, the possibility of steam injection into the field was evaluated for the long run. Due to extreme heterogeneity and fractured structure, crestal steam injection that uses steam as heating rather than a displacement agent was proposed. An analytical study for the optimization of steam injection was provided.To determine the locations for the above listed processes, an extensive reservoir characterization study was performed using dynamic and very limited static -well- data. Using well recorded primary (1961-1986) and CO2 production data (1986-2007), fracture swarms were mapped. In this process, the changes in the initial production rate and GOR over different time periods were considered. The quickest decline in the initial rate and the lowest GOR areas correspond to highly fractured regions. Highly -vertically- fractured areas (typically the crest) were determined for potential steam injection. This analysis also helped detect high quality matrix areas as candidates for chemically augmented WAG.
Advanced Compositional Gradient Analysis
Authors: Cañas Jesús , Pop Julian , Dubost Francois , Elshahawi Hani 
Published: September 2008

Abstract
Steep gradients are common in gas condensate and volatile oil reservoirs, but they are also present in heavy oils reservoirs. There are numerous publications (Creek, 1985, Lars Høier, 2000, Montel, 2002, Firoozabadi, 1999, Ghorayeb, 2003, Fujisawa, 2004, Elshahawi, 2005, and Kabir, 2006) that have dealt with complex fluid columns showing compositional gradients for columns in thermodynamic equilibrium or under steady state conditions. Montel et al. (2002) discuss processes that arise from recent charging of these reservoirs, which are not in equilibrium but still undergoing for instance a flux of the light components that diffuse.
Formation testers supply a wealth of information to observe and predict the state of fluids in petroleum reservoirs, through detailed pressure and fluid analysis measurements. With the correct understanding of fluid characteristics in the reservoir, reserve calculations and adequate development plans can be prepared. Additionally, flow barriers may then be revealed, as across such barriers, fluid may appear different. In order to test for the existence of such barriers, pressure or fluid differences, in their context must be assessed. Formation tester data must therefore be treated by means of a systematic analysis, so that different sources of information lead to an integrated, preferably, consistent conclusion. Downhole fluid analysis in conjunction with pressure gradient analysis is simultaneously analyzed to reflect and make deductions concerning the correct state of fluids in complex fluid columns. As part of the process, different reservoirs need to be well delineated through appropriate statistical similarity tests of pressure gradients and fluid analysis of the different zones (Kabir, 2006).
In this paper, a novel methodology is presented to account for non-linearity in pressure gradients due to varying fluid density. We examine two field cases in which compositional gradients were observed with both downhole fluid analysis measurements and pressure gradients. An equation of state model is used to describe the fluid column according to a simple fluid equilibrium model. A non-linear pressure gradient regression fit is also examined. The choice and appropriateness of the pressure gradient model that accounts for the observed fluid density changes observed. The result of the modelled fluid and pressure analisis are compared to actual downhole measurements of the pressure profile and insitu fluid logs. In particular, pressures and densities calculated from the multiple sources of information, pressure and fluids, are compared to direct actual measurements. The reservoir architecture is revealed. For both cases, the fluid column is continuous through the hydrocarbon intervals down to the water-oil contacts. Flow barrier locations would be found on the basis of anomalies and departures of the measured data from the modelled pressure and fluid gradients.
Integrated Fracture and Production Modeling Study in the Lower Cotton Valley Sands, Northern Louisiana
Authors: Lolon E. P. , Mayerhofer M. J. , Garcia I. , Durey D. A. , Byrd A. C. , Rhodes R. D. 
Published: September 2008

Abstract
The Lower Cotton Valley (LCV) sands in northern Louisian are a complex reservoir system consisting of multiple, low permeability layers. In this area, wells are hydraulically fractured to achieve economic gas production. However, due to the high-stress environment, fracturing pressures are typically very high, in most cases close to or above overburden stress. This presents significant challenges for stimulation effectiveness.
This paper discusses well performance evaluations and possible answers as to why wells are not performing as expected. Possible causes of wells exhibiting steep production declines within the first few months after completion and solutions to improve well performance and well completions as well as field development strategies are addressed. The results of fracture modeling and detailed single-well production modeling are presented.
All wells in the study area show evidence of damaged hydraulic fractures. Potential damage mechanisms are discussed including high production drawdowns and large effective stresses on the proppant in conjunction with high temperature, fracture complexity, dipping fractures, and formation collapse.
Counter-Diffusion and Competitive Adsorption Effects During CO2 Injection and Coalbed Methane Production
Authors: Fathi Ebrahim , Akkutlu I. Yucel 
Published: September 2008

Abstract
Previous investigations have shown that carbon dioxide injection and enhanced coalbed methane production (CO2-ECBM) involves several viscous and diffusive transport mechanisms, raising challenging questions related to the chemically and structurally intricate nature of coalbeds. Injection of gas in a network of natural fractures initiates counter-diffusive transport and competitive (and often selective) sorption processes among the gas molecules in coal. Consequently, the incoming CO2 molecules activate and displace the in-place CH4 molecules. Competitive sorption rates, however, could be controlled by the counter-diffusive mass fluxes during the gas injection and production operations. Nature of the multi-component diffusive transport processes should therefore be understood clearly. In this paper, we develop a new one-dimensional theoretical framework suitable for a fundamental level investigation of binary gas storage and transport in coal seams considering a serial multi-continuum porous medium with triple porosity and dual permeability. Total pore volume is due to micro- and macropores and due to a high-density fracture network. Macropores and fractures are characterized by their own effective uniform permeability fields; hence, they are continua for fast viscous/diffusive transport of the free gas. Micropores, on the other hand, are primary pores retaining the bulk of the gas in-place at an adsorbed state. Resistence in the micropores is due to surface diffusion of the adsorbed binary mixture. The generalized Maxwell-Stefan formulation of multi-component transport is revisited and extended to describe gas behavior in bimodal (micro- and macro-) pore structures. We first show that the widely used single-component Langmuir gas behavior is, in fact, a limiting case of the generalized form. The latter includes not only the anticipated binary effects (due to the existence of two components with different molecular size and adsorption capacity) but also additional nonlinear effects due to the direction of diffusive mass fluxes and to the lateral interactions of the adsorbed gas molecules in the micropores. Following, we incorporate the multi-component formulation to a reservoir flow model to consider CO2-ECBM process in between an injector/producer pair. Dynamics of sequestration and production is then investigated varying initial/boundary conditions. It is shown that the counter diffusion and competitive adsorption effects in the micropores could generate nontrivial effects at the reservoir-scale such that methane production is significantly enhanced. The investigation is important for our understanding and the design of CO2-ECBM processes.
Characterization of Oil Water Flows in Inclined Pipes
Authors: Atmaca S. , Sarica C. , Zhang H. -Q. , Al-Sarkhi A. S. 
Published: September 2008

Abstract
The flow of oil-water for different inclination angles (0°, ±1°, ±2° and -5°) was studied through the analysis of high-quality experimental data on flow pattern, pressure gradients, water holdup and phase distribution (Atmaca (2007). A total of 324 tests were conducted in a 0.0508-m. ID 21.1 m. long, inclinable test section using tap water and mineral oil (with a density of 0.85 gr/cm3 and viscosity of 15 cp) with superficial velocities ranging from 0.025 m/s to 1.75 m/s.
Oil-water flow in the petroleum industry is a common occurrence during production and transportation of gas-oil-water in pipes. Facilities design is strongly dependent on the flow behavior. The specific applications include design and troubleshooting of flow lines and wells, separator design, interpretation of production logs, etc.
Non-intrusive high-speed camera technique was used to determine the flow patterns at various conditions. Experimental flow pattern maps were compared against Trallero (1995) and Zhang and Sarica (2006) models. Trallero model predicted the most flow pattern boundaries well except stratified flow pattern. For most of the cases, the pressure gradients were over predicted by the Zhang and Sarica model. Quick closing valves are used for holdup measurements giving phase slippage information. For the low superficial velocities, slippage behavior was observed very clearly for upward and downward flow. For the high superficial velocities, slippage effects were diminished. Representative phase distributions, and interface boundaries were observed for different flow conditions by examining conductivity probe data.
This paper provides significant insight in phase distribution and slippage behavior. The results presented in this study are applicable not only to oil-water flow but also to three-phase gas-oil-water flow models.
A Mixing Rule of Self-Diffusivities in Methane Hydrocarbon Mixtures and the Determination of GOR and Oil Viscosities from NMR Log Data
Authors: Chen Jiansheng , Chen Songhua 
Published: September 2008

Abstract
A new mixing rule is described for the prediction of the self-diffusivities of gas and liquid hydrocarbon molecules in methane-oil mixtures. Unlike macroscopic fluid properties such as density and viscosity, molecule self-diffusivity is a microscopic parameter associated with individual molecule species. Thus, a self-diffusivity of a binary mixture of gas and oil is non-existent. Instead, the self-diffusivity of each species in the binary system is affected by presence of the other species. For that reason, the commonly used log-mean based mixing rule that applies to macroscopic properties of the mixtures is unsuitable for self-diffusivity when the reference states are pure Component 1 and pure Component 2. We found that it is necessary to introduce two new reference states: one is the infinite dilution of Component 1 in Component 2; the other is the infinite dilution of Component 2 in Component 1. The component can be a single-molecule species or a mixture; as long as its self-diffusivity or self-diffusivity distribution can be measured. Using this approach, the self-diffusivity of each component in the mixture follows the log-mean based mixing rule. This new mixing rule is verified with literature data of methane-hexane, ethane-hexane, methane-octane, ethane-octane, methane-decane, and ethane-decane mixtures over a wide range of temperatures, pressures, and solution gas concentrations.
The new mixing rule is applied, and a detailed procedure is developed, to determine the Gas Oil Ratio (GOR) and the live-oil viscosity for in-situ volatile oils from NMR log data. First, the self-diffusivities and proton fraction of the methane and oil mixture are determined by fitting the NMR-measured diffusivity distribution with a bi-modal distribution. Then, the self-diffusivities for the four reference states are calculated using the mixing rule. Finally, the GOR is calculated from the proton ratio; while the live-oil viscosity is calculated from the self-diffusivity of pure oil and GOR. The calculated GOR and oil viscosities are compared with the PVT measurement of the oil sample taken from downhole and show good agreement. GOR and oil viscosities from this new technique can be used for optimizing testing and sampling programs, for reservoir stimulation studies, and for the design of surface production facilities.
Design, Implementation and Operation of an Advanced Collaborative Environment for Enhanced Performance in Tangguh Drilling and Completions
Authors: Pickering J. G. , Cavanagh D. , Allen S. , Hanneman A. , Bennett C. , Ananta D. , Whiteley N. 
Published: September 2008

Abstract
The Tangguh Project in West Papua Province, Indonesia represents significant challenges in terms of drilling conditions, extreme remoteness, and social and environmental sensitivity. The Tangguh Drilling "Advanced Collaborative Environment" (ACE) was designed to enhance drilling performance and safety. Very positive results were achieved within the first months of the drilling operation. This paper describes the design approach, implementation and subsequent operational experience of the Tangguh Drilling ACE. A number of features of this ACE have since become exemplars for BP's drilling operations globally.
The two-rig Tangguh development drilling campaign of 15 wells faced particularly difficult challenges with total losses, high vibration and the extreme remoteness of a location two timezones ahead of the office. To enhance drilling performance, an ACE was developed based on BP's global design principles covering people, process, technology, physical environment and organisation. The ACE connects each rigsite drilling team to the BP office in Jakarta and the onshore supply base. Real time drilling data in WITSML (Wellsite Information Transfer Standard Markup Language) format and high quality video conferencing were essential components to support the Wellsite Leader in the execution of the drilling plan.
Tangguh drilling commenced in May 2007 with a successful 10 months of field operations. The Wells Manager attributed a significant part of this success to ACE and associated working practices. The drilling ACE made a significant contribution towards reducing the recovery period from major non-productive time incidents and has promoted better connectivity between rigsite and office. This has improved teamwork and the sharing of information. It is consistent with BP's goal for Field of the Future™, "Better Decisions Faster".
Critical to the success of the ACE was engagement and ownership by the Wellsite Leaders and drilling operations management. Significant organisational and interface challenges were overcome, including applying vendor neutral data standards between different service companies. This was a first for Indonesia. A number of other firsts were achieved also:- First BP drilling ACE designed specifically for performance enhancement.First BP multi-rig drilling ACE.First drilling ACE in BP using full time high quality video conferencing over satellite and wireless broadband.
Improved Gridding Technique for Coupling Geomechanics to Reservoir Flow
Authors: Tran David , Buchanan Lloyd , Nghiem Long 
Published: September 2008

Abstract
The application of geomechanics in reservoir flow simulation has increased substantially since it was recognized that the modeling of geomechanical effects was necessary to predict important phenomena such as compaction, subsidence, wellbore failure, etc. However, its application is strongly limited due to the use of a one-grid system for both reservoir flow and geomechanics deformation. In the case of a large field-scale simulation, the use of a one-grid system gives rise to an extremely large number of gridblocks. On one hand, for an accurate modeling of fluid flow, the gridblocks need to be reasonably small around wells and sharp fronts. Yet, these small gridblocks may not be essential for geomechanics computations. On the other hand, accurate geomechanics calculations may require many gridblocks in the overburden, underburden and sideburden (country rock) that are not necessary for fluid flow. In this work, a separate-grid technique is combined with an iterative coupling method to resolve the above problem. In this separate-grid technique, the reservoir flow grid and the geomechanics grid are distinct in order to model efficiently both fluid flow phenomena and geomechanics deformations. A method to couple the two grid systems is described. The use of this grid coupling approach reduces the simulation run time substantially with results that are very close to the one-grid method. A series of examples illustrating the application of this two-grid concept and the corresponding run-time reduction are described.
Fracture Ballooning in Naturally Fractured Formations: Mechanism and Controlling Factors
Authors: Majidi R. , Miska S. Z. , Yu M. , Thompson L. G. 
Published: September 2008

AbstractFracture ballooning observed while drilling naturally fractured formations has often been mistakenly interpreted as influx of formation fluid or the loss of drilling fluids. This misinterpretation leads to costly well control procedures that may make the situation even worse. The main mechanisms and factors controlling the ballooning phenomenon must be well understood to avoid confusing this phenomenon with conventional losses or formation kick. Amongst several mechanisms that are quoted for borehole ballooning, the opening/ closing of natural fractures plays a major role in naturally fractured formations.In this work, a mathematical model describing the fracture ballooning process is developed and solved numerically using finite difference approximation. The governing equation is derived using principles of conservation of mass and linear momentum for transient radial flow in a single fracture. The effects of fracture parameters (aperture, extension and deformability) have been studied as well as fluid properties and operational conditions. Describing drilling fluid rheology with Yield-Power-Law (Herschel-Bulkley/YPL) allows for the investigation of the effect of drilling fluid rheology on borehole ballooning.Results show how the rheological properties of drilling fluid such as yield stress and shear-thinning/thickening effect, influence ballooning or mud losses in fractured formations. We conclude that the fluid loss in the fractures could be stopped either because of high yield stress of drilling fluid or limited extension of the fracture. The proposed model is also helpful for detecting and treating ballooning as well as evaluating fracture characteristics. The field potential application of the model is described.
Case History: Expanding the Boundaries of a Hydraulic Workover Unit into New Economic Levels
Authors: Attong D. , Robertson D. , Wyatt M. , Perai S. , Persad S. , Joseph K. , Garcia J. F. , Fleary C. 
Published: September 2008

Abstract
A 600K Hydraulic Workover (HWO) Unit has proven that it has the capability to safely access and deliver offshore gas reserves. This paper identifies the business environment, challenges, learnings, results and the key success factors of a three (3) well project that delivered a total of 250 million standard cubic feet per day (mmsfcd) using a 600K HWO unit. The primary result of the project demonstrated the capability of the HWO unit in handling challenges previously thought better suited for conventional larger rigs. HWO units have proven to be particularly effective in bpTT's offshore operations, however their application had been limited to tubing changeouts, workovers, oil recompletions and short oil sidetracks. This project expanded the capability of the 600K HWO unit to perform high rate uphole gas recompletions. The project consisted of three uphole gas recompletions in 9-5/8 inch casing. Each recompletion was executed at approximately $0.50/barrel of oil equivalent (boe) which made the project extremely attractive and made gas reserves economically viable. Completing the same work with a larger Jackup unit would have cost $3 -4/boe clearly showcasing the economic advantage of the HWO unit. Another major advantage was the ability to move the HWO unit in unfavourable weather conditions when compared to a Jack Up rig. Weather conditions can result in significant and costly delays during the December – April period for jack up units.