bluuebunny/crossref_metadata_2025_split huggingface dataset:
Monitoring of In-Situ Combustion Process in Southern Part of Balol Field Through Analysis of Produced Fluids
Authors: Dayal H. S. , Pandey Vivek , Mitra Sujit , Bhushan B. V. , Bhandari A. C. , Dwivedi M. M. 
Published: December 2011

Abstract
Balol field is located in the heavy oil belt of North Cambay Basin in the state of Gujarat, India. The API gravity and oil viscosity is 15° and 300 cp respectively. Low primary recovery of 13% necessitated the application of ISC (In situ Combustion). The success of ISC in the southern part of Balol field has led to more than four-fold increase in oil production. Oil rate increased from a level of 60 m3/d to about 260 m3/d together with decline in Water cut from 82 % to 40% with injection of air @ 0.18 MMSm3/d. The ISC process was first implemented on commercial scale in October 1997 and has been instrumental in achieving the recovery of about 50 % of STOIIP from southern sector.
In ISC process in Balol, air is injected through injection well which is ignited artificially, to initiate the process in high temperature oxidation mode. The combustion takes place when oxygen, crude oil react to generate heat alongwith water and combustion gases. Oil is displaced by the vaporizing action of the thermal front and sweep provided by the combustion gases, hot water and steam. Nitrogen does not take part in the reaction and makes a free trip to the producers.
The produced fluids like flue gas, oil and water were collected at regular intervals, their composition were measured for monitoring the In-situ combustion process. The increase in CO2 concentration to the level of 15 %, reduction in oil viscosity and water salinity by half, increase in Well Head temperature and SO4 ion concentration in produced water enabled in understanding of various aspects of combustion process like confirmation of ignition, front movement and burn efficiency.
This paper elaborates how monitoring has helped in re-orientation and optimisation of air injection leading to manifold increase in oil production. Currently, oil recovery is close to the envisaged recovery factor.
Optimal Application Conditions for Heavy-Oil/Bitumen Recovery by Solvent Injection at Elevated Temperatures
Authors: Leyva-Gomez H. , Babadagli T. 
Published: December 2011

Abstract
Steam injection is the most common technique in heavy oil/bitumen recovery. However, the emission of greenhouse gases into the atmosphere, its water requirements and excessive operational cost and problems entail finding alternative solutions. One approach is combining steam and solvent injection by taking advantage of steam injection preheating the reservoir for more effective solvent recovery application. In this case, the performance of subsequent solvent injection strictly depends on the temperature and pressure in the reservoir. Recent experimental studies on superheated solvent injection showed that solvent in the gas formed near the saturation line yields an optimal recovery minimizing the asphaltene precipitation and maximizing the recovery. This paper investigates this process through a numerical modeling exercise and formulates the optimal pressure and temperature conditions for different reservoir conditions and hydrocarbon solvents.
We first report the results of numerical simulation of laboratory experiments, in which heavy oil was exposed to solvent vapour at high temperatures. To achieve these results, a radial 3D numerical model of 15x1x63 cells was constructed using a commercial numeric simulator. The injection of either propane or butane into sand packs or consolidated sandstones at elevated temperatures was simulated. A pressure-temperature sensitivity analysis was carried out for different core sizes to understand the dynamics of the gravity drainage process associated with asphaltene precipitation. Asphaltene pore plugging behaviour was modeled and diffusion of solvent into the heavy oil was analyzed to determine both ideal solvent type and optimal operating conditions for solvent injection at high temperatures.
Our preliminary results and observations showed that the solvent should be in the gas phase and its sensitivity to temperature and sample height (for effective gravity drainage) is more critical than the pressure. There also exists a critical temperature that yields amaximum recovery and this value was determined for the rock/reservoir types and solvents considered in this study. Solvents considered, i.e., propane and butane, behaved differently in terms of asphaltene precipitation and its effects on ultimate recovery. The history matching to the experimental data was achieved primarily by considering this effect.
Engineering a Successful Sour, Heavy Oil Test in a Sensitive Offshore Environment in Saudi Arabia
Authors: Al-Nahdi AbdulHakim , Gill Harmohan , Farid Usman , Morris Ronald , Omidiya Abdur-Rasheed 
Published: December 2011

Abstract
Exploration for heavy oil, in an offshore setting carries special challenges and risks, especially during the well testing phase. Bringing the heavy oil to surface and then disposing of this oil efficiently without polluting the offshore environment is a challenge. Flow testing oil with APIs as low as 8 degrees would be challenging in itself; when this oil is also sour, the challenges are magnified many-fold, especially when considering the limited space on offshore drilling rigs.
Saudi Aramco has started a program aimed at exploration and evaluation of heavy oil reserves in the Arabian Gulf. The objective of testing this sour, heavy oil was to obtain reservoir fluid samples, get productivity data and characterize the reservoir. While attempting to dispose of the oil in an efficient manner, initial attempts to test this heavy oil were unsuccessful. Prematurely terminating these tests resulted in not obtaining all of the required test data.
A heavy oil team was formed in early 2008 to determine solutions to the inability to properly characterize the reservoir on heavy oil well tests. This multidisciplinary team of professionals held two workshops, where heavy oil experts from major service companies provided their global expertise. This information was then blended with local operational requirements to create a unique well testing design. This design has successfully been implemented in two wells (onshore and offshore).
The use of an Electric Submersible Pump (ESP) although common in production scenarios, was successfully implemented for the first time on a heavy oil drill stem test in Saudi Arabia.
This paper summarizes the problems associated with testing heavy oil, the options studied, the reasons for selection of the chosen test method, the downsides of the selected plan, the trial testing on land and the successful implementation of the final plan in an offshore environment. It is a summary of the planning process necessary to get a good heavy oil test in a sensitive offshore environment.
Predicting Lower Fars Heavy Oil Molar Compositions Using Artificial Neural Networks
Authors: Al-Sirri Dalal , Gharbi Ridha 
Published: December 2011

Abstract
Characterizing reservoir fluid composition is a crucial step in all phases of the exploration and development cycle of any oil field. The petroleum industry has dedicated much work to build up computational techniques to model phase behavior through two approaches using conventional regression methods and the Equation-of-State models. Recently, Artificial Neural Networks (ANN) have been successfully used to solve numerous problems in the petroleum industry. This interest is due to the fact that neural networks generally have large degrees of freedom, thus they can capture the nonlinearity of the process being studied better than regression techniques. In addition, neural networks have the ability to model systems with multiple inputs and outputs.
The objective of this study was to develop a neural network model to predict the molar compositions of heavy oil as functions of the well location, depth, bottomhole temperature, bottomhole pressure, API gravity, and gas gravity. Since composition may change vertically as well as laterally, well location and depth of the samples are included in the training of the neural network. A total of nine pseudocomponents are used as output variables.
The data, on which the network was trained, contained 82 data sets collected from Lower Fars heavy oil reservoir of north Kuwait. Several neural network architectures were investigated to obtain the most accurate model. Results indicate that general regression neural network shows optimum prediction capability for molar compositions as functions of the input variables. In addition, the model was able to successfully predict the molar compositions from inputs that were not seen during the training process. The output of this study is in accordance with the new vision and strategy that Kuwait Oil Company has set toward the exploitation of the unconventional heavy oil resources of Lower Fars reservoir of North Kuwait in which a lot of new wells will be drilled in this area. A development of such a new and innovative prediction model using ANN approach is of great importance in providing the molar composition of Lower Fars heavy oil reservoir, starting only from basic available data, with a limitation of a reliable PVT data base.
Importance of Thermal Consolidation of Shale During SAGD Process
Authors: Bois Axel-Pierre , Mainguy Marc 
Published: December 2011

Abstract
Most of the oil sand deposits contain shale barriers of various sizes and with a space distribution difficult to appraise. These shale barriers can lower the reserves and reduce the efficiency of the SAGD process by slowing down steam chamber propagation. The detrimental effect of shale barriers on the SAGD process has been demonstrated by many simulation works and research projects have been launched to develop new technologies favoring breakdown of shale barriers.
The effects of high temperatures on shale are difficult to assess. Field data from SAGD projects show that steam might either bypass shale barriers or breakthrough them, but the conditions favoring these mechanisms are unclear. Lab data show that the constitutive mechanical behavior of clayey materials is strongly sensitive to high temperatures. Of particular importance is the phenomenon of thermal consolidation of clay which was never pointed out to explain the conditions of failure of shale barriers during SAGD. Thermal consolidation denotes an irreversible contraction of clayey materials when heated under drained condition.
This paper presents the results of a project that aimed at evaluating if thermal consolidation could help increase permeability of shale barriers. A comprehensive review of published data shows that the origin of this phenomenon is still poorly understood despite some important factors can be highlighted. It also shows that stress path applied during thermal expansion tests on shale specimens strongly control the thermal consolidation phenomenon, which can lead to erroneous interpretations of these tests. It proposes a very simple model that is used to show 1) under which conditions thermal consolidation of shale barriers might happen; and 2) the consequences of thermal consolidation in terms of permeability changes of shale.
Downhole Fluid Sampling in Shallow Viscous Reservoir - Innovative Techniques Helped in Overcoming the Challenge
Authors: Ahmed Khalid , Al-Sammak Ibrahim , Ahmad Fatma , Abbas Faisal , Vasquez Rafael , Al-Jabari Naim , Cook Reg 
Published: December 2011

Abstract
Downhole fluid sampling in shallow unconsolidated reservoir having high inter-granular porosity and filled with viscous oil is quite challenging. The dominant formation properties, relevant to fluid flow, like low pressure, rock’s mechanical weakness, drilling damage and fluids mobility ratios, despite very high permeabilities, have resulted in the failure or impracticality of the conventional and most obvious methods- for example the sampling with Dual/Straddle Packers.
The problems faced during sampling are: i) plugging of flowline, ii) emulsion generation iii) sand production- leading to caving around sampling tool and iv) marginal operating limit of pressure drawdown-dictated by extremely low formation pressure and little difference between hydrostatic and formation pressures. Mostly, the flow happens in surges and any increase in flow rate causes large drag on sand grains and excess pressure drawdown.
A thoughtful mix-up of technology, understanding of rock mechanics, innovative operating techniques and proper coordination by aligning all concerned has helped in meeting the challenge of sampling viscous oils in the unconsolidated sand.
A log-based Geo-Mechanical study suggested very low unconfined compressive strength for the sand, restricting the flow rate to as low as 2 cc/s. Dual/Straddle Packers, with its large volume at this low flow rate, would require very long hours of pumping. Typically, the volume between packers would take 5 to 6 hours of continuous pumping at the suggested maximum rate of 2cc/s; just sufficient to start pumping out from the formation. A normal probe would cause sanding at probe head due to the reduced cross section to flow. The most successful approach was the selection of: a) probes with enlarged cross section to flow, which reduce the drawdown by decreasing the flow velocity at the sand face, b) ultra slow pump out rates to negotiate drawdown, formation weakness and mobility ratios of water/filtrate and viscous oil.
Multiple sand filters in the flow line, segregation of emulsified filtrate through innovative techniques and state-of-the art fluid analysis methods helped to determine exactly when the viscous oil started to flow. However, the surge nature of flow still resulted in 20 to 30% contamination in the sampled oil.
The obtained PVT-quality downhole sample helped in determining the in-situ fluid properties of the viscous oil.
Analysis and Prediction of Heavy Oil Two-Phase Slug Length in Horizontal Pipelines
Authors: Al-Safran E. M. , Gokcal B. , Sarica C. 
Published: December 2011

Abstract
The recent trends of increasing energy demand led the industry toward the development of heavy oil unconventional resources. However, the production and transportation of such heavy oil is a challenge due to the lack of understanding of the two-phase flow behavior under the condition of high viscosity liquid phase. The objective of this study is to physically understand and quantify the effect of liquid viscosity on slug length and develop two-phase slug length correlation for high oil viscosity. The developed slug length correlation can improve the existing mechnistics two-phase flow models in the development and maintenance of heavy oil fields.
Experimental high viscosity (0.181-0.589 Pa.s) two-phase air/mineral viscous oil slug length data is acquired in a horizontal 0.0508-m ID pipe. Data analysis showed a one third reduction in the average slug length compared to the average slug length under low viscosity condition. Furthermore, statistical analyses showed a significant effect of liquid phase viscosity on slug length distribution including maximum slug length and slug length variation. High speed recorded flow visualization revealed the effect of liquid phase viscosity on the scooping and shedding processes at the front and back of the slug, respectively; which is speculated to reduce the slug length. In addition, a proposed physical model suggests that the thick liquid film in the Taylor bubble zone and the short slug mixing zone result in a fully developed velocity profile at slug back stabilizing the slug at a shorter length. A new dimensional analysis based model is proposed to predict average slug length for high viscosity liquid slug flow. A validation and comparison study of the proposed correlation showed the best performance amongst the existing correlations.
Surveillance Improvements During the Implementation of a Large Scale Carbonate Steamflood Pilot, Wafra field, PZ
Authors: Hoadley Steven , Al-Yami Falah , Deemer Art , Brown Joel , Al-Mutairi Ghanim , Lekia Solomon , Al-Dhafeeri Fahad , Al-Odhailah Fares , Barge David 
Published: December 2011

Abstract
A large scale carbonate steamflood pilot is being conducted in the Wafra field in the Partitioned Zone between the Kingdom of Saudi Arabia and the State of Kuwait. The primary objectives of the pilot are to reduce the technical uncertainties and economic risks associated with carbonate steamflooding and to determine feasibility for full field steamflood development. To help in accomplishing this objective, a Surveillance Plan, linked to an uncertainty management plan, was developed and implemented to focus the data gathering and analysis necessary to meet the project objectives.
The uncertainty management plan identified key uncertainties that must be mitigated to reduce the risk for full field steamflood development in the Wafra field. To reduce these uncertainties, a thermal surveillance plan was created that represented the measurements required on reservoir and facilities performance to evaluate the pilot performance and provide the information needed for the design and operation of a full field development. Each data element identified in the surveillance plan required a process for collecting, quality control, and storage of the information. The surveillance plan is designed to be an evergreen document with the flexibility to add and define new data collection requirements as required by the project response.
Because there are few carbonate steamfloods in the world, the LSP project has unique challenges that have not been typically encountered in other better understood sandstone thermal projects. Some surveillance activities were expanded as a result of observations occurring in the field and were added to the surveillance plan to enhance the understanding of the steamflood response.
Heavy Oil Production With Steam Injection Using ESPs
Authors: Issa Mohammed , Fleming James , Wonitoy Kelvin 
Published: December 2011

Abstract
Heavy oil production using steam injection has become a common method of extracting oil. It is considered an enhanced oil recovery (EOR) method and is one of the extraction methods used in thermal stimulation of oil reservoirs. Steam injection is widely used in the San Joaquin Valley of California (USA), the oil sands of northern Alberta (Canada) and Venezuela. Steam assisted gravity drainage (SAGD) has become one of the more cost effective methods of producing fluid from oil sand reservoirs. This same technology is being applied to heavy oil reservoirs where viscosity is an issue.
Wells involving steam injection operate at bottom hole temperatures (BHT) of 180°C to 250°C This is true when electrical submersible pumping systems (ESPs) are used, however when gas lift or rod lift are employed the BHT can exceed 320°C. This market requirement pushed the vendors to develop ESPs capable of operating continuously at these temperatures for reasonably acceptable run times (2 yrs +). The equipment specifications for materials and designs for this type of application involve the use of many high tech metals and elastomers designed for extreme temperature operation and temperature cycling.
Steam assisted recovery projects challenge the ESPs with elevated temperatures, temperature cycling, H2S corrosion, abrasives, steam, and free gas.
Development of steam injection projects parallel the similar requirements for equipment development used to run in harsh environments (high H2S), H2S-resistant materials can be used in varying configurations depending on the H2S quantity and the BHT. High-strength shafting and corrosion-resistant couplings, fasteners, and housings offer the most protection from corrosive elements. Cable and motor lead extensions (MLE) benefit from the application of lead barrier protection. Major developments in the insulating materials required for the stator, cable and motor lead extension enabled operators to increase the reliability of the ESP even when exposed to high temperatures and corrosive environments.
The Centrilift CENtigrade™ elevated temperature production systems family is able to operate successfully in the harshest conditions. This product family consists of the Centrilift High Temperature™ ESP system, Centrilift Extreme Temperature™ ESP system, and Centrilift Ultra Temperature™ ESP system. Baker Hughes has a proven record of success with this equipment (Fort McMurray oil sands in Alberta, Canada), making it the first company to deploy ESPs capable of operating reliably at bottom hole temperatures as high as 250°C. The Baker Hughes Centrilift™ artificial lift product line offers ESPs, progressing cavity pumping systems (PCPs), gas lift, and surface pumps.
This paper will focus on the development, capabilities and the successful implementation of the CENtigrade production systems.
A New Perspective on Tracking Energy Transfer in SAGD derived from Three-Dimensional Numerical Field Scale Simulations
Authors: Ezeuko C. C , Wang J. , Sen A. , Gates I. D. 
Published: December 2011

Abstract
Numerical reservoir simulations have successfully been used for performance analysis of several commercial steam assisted gravity drainage (SAGD) heavy oil recovery projects. The inherently complex calculations involving mass and energy balances, along with consideration for advanced geomechanics, culminate in a strong time limitation for field scale simulations of SAGD processes. As a result, significantly homogeneous gridding has traditionally been used for downwell directions, with grids sizes sometimes exceeding 100 m for three dimensional simulations of SAGD. This represents a compromise which requires further quantitative analysis to clearly understand the implications on uniform steam chamber development and the accuracy of performance predictions. At this point, most simulations are not capable of predicting realistic field performance, especially in the downwell direction, of a given reservoir since grid resolution is poor. In this study, a full field reservoir model representative of a McMurray reservoir is used to analyze the implications of longitudinal grid homogeneity on the propagation of a SAGD steam chamber. In addition, a novel use of flowing steam quality plots to visualize steam migrations and characterize heat transfer during SAGD is presented. The results illustrate the requirements on grid block dimensions necessary to resolve heterogeneities and accurately represent physical phenomena such as flow and heat transfer. The findings of this work provide useful guidelines and have implications for future design and performance analysis of SAGD projects using numerical reservoir simulations.
How Would the Mandatory Adoption of IFRS Affect the Earnings Quality of U.S. Firms? Evidence from Cross-Listed Firms in the U.S.
Authors: Sun Jerry , Cahan Steven F. , Emanuel David 
Published: December 2011

SYNOPSIS
We examine the impact of IFRS adoption on the earnings quality of foreign firms cross-listed in the U.S. from countries that have already adopted IFRS on a mandatory basis. We use the cross-listed firms as surrogates for the U.S. firms so we can observe the effect of IFRS adoption in the U.S. We examine five measures of earnings quality related to discretionary accruals, target beating, earnings persistence, timely loss recognition, and the earnings response coefficient (ERC). To isolate the effect of IFRS adoption, we use a matched sample design where each cross-listed firm is matched to a U.S. firm. We find the difference in earnings quality from the pre- to post-IFRS period is not different for the cross-listed and matched firms when earnings quality is measured by absolute discretionary accruals, timely loss recognition, or a long-window ERC. However, for the incidence of small positive earnings and earnings persistence, we find significant difference-in-differences, indicating that IFRS adoption led to an improvement in earnings quality for cross-listed firms relative to the matched firms. Our results are slightly surprising since U.S. GAAP is generally viewed as high-quality standards with little room for improvement.