bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design of SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) Method for Heavy-Oil Recovery Using Hybrid Optimization Framework
Authors: Al-Gosayir M. , Babadagli T. , Leung J. , Al-Bahlani A. M. 
Published: December 2013

Abstract
In order to reach the ultimate heavy oil and bitumen recovery with minimal cost, efficient and optimized design for recovery processes operation strategies is necessary. Despite the amount of the heavy oil and bitumen reserves around the world, the production is limited due to the production development difficulties such as high cost, complex processes, and environmental concerns. Many design and performance evaluation studies published in the literature combine numerical simulation with graphical or analytical techniques; however, only few design elements are handled due to the difficulties of handling large number of factors. Due to the high computation requirements, limited efforts that integrated the simulation exercise with global optimization algorithms to handle more design elements.
In this paper, a hybrid global optimization framework is used to optimize the design of a new process called Steam-Over-Solvent in Fractured Reservoirs (SOS-FR) proposed by Al-Bahlani and Babadagli (2008, 2009a-b, 2011a-b). The hybrid framework integrates genetic algorithm with orthogonal arrays and response surface proxies for better convergence behavior and higher computational efficiency. The SOS-FR technique consists of a heating phase using steam injection, subsequent solvent injection, and low temperature steam injection for solvent retrieval and additional oil recovery. Solvent injection can be continuous or cyclic where the solvent is injected, soaked, and then fluids are produced. This paper studies both scenarios over single and multiple matrix field scaled reservoirs by adjusting the injections’ durations and rates. As a result, about 30 design elements for four base benchmark models are optimized, and the profit and efficiency is doubled comparing with the benchmark models using optimal injection scheme suggested by our optimization framework.
Challenges in Testing and Completion of Highly Sour HPHT Reservoir in The State of Kuwait
Authors: Al-Salali Yousef , Al-Bader Haifa , Duggirala Vidya Sagar , Manimaran A. , Packirisamy S. , Al-Ibrahim Abdullah , Rajkhowa Anupam 
Published: December 2013

Abstract
Testing and completing deep reservoir in the state of Kuwait is challenging due to high contrast in formation pressure over the 4,000 feet section (13,500’ to 17,500’). Recently, a new structure located in the North-Western part of Kuwait area was drilled and tested with deep drilling rig. Formations in this deep structure have very low porosity and permeability with naturally fractured reservoir. During short term testing, wells produced oil and gas with unexpectedly very high H2S(20%–35%), the highest H2S content in any reservoir so far discovered in the state of Kuwait. Since the reservoir was rated as HPHT and sour, it was a challenging experience to test all the wells safely and successfully. Unfavorable conditions such as high pressure, high temperature, high H2S and CO2 content require special equipment, tools and treatment to test and complete exploratory wells.
The targeted formations were perforated using deep penetration TCP guns, stimulated with emulsified/retarded acid, tested with Drill Stem Testing(DST) tools and sampling was done. Meticulous planning and testing strategies could overcome all challenges and high sour reservoir was successfully tested safely without any incident. The wells were flowed only for short period due to high sour nature of the reservoir fluid and safety reasons. However, data collected during short term testing helped in understanding production capability, fluid and reservoir characteristics which is vital for delineation/development of the new field. Methods developed, data obtained and expertise gained in testing and completing high sour wells will be useful for the future development of sour gas reservoir.
Aim of this paper is to describe the actual challenges encountered and lessons learned during testing and completion of hostile environment wells. This paper also aim to present techniques and approach adopted to address the operational risk and HSE issues during perforation, Coiled Tubing, stimulation, well testing and sampling operations.
Reservoir Connectivity Evaluation and Upscaled Model Screening Using Streamline Simulation
Authors: Fanjul Javier Prieto , Vicente Mario Gustavo 
Published: December 2013

Abstract
Significant gas potential has been identified in both conventional and unconventional reservoirs in emerging gas projects in Algeria, south-western Sahara. This study is focused on Lower Devonian reservoirs, which overall depositional model is characterized by shallow marine shelfal to tidal sandstones and mudstones in a range of depositional settings, with thin thickness (less than 10 m) and low porosity and permeability, at 3000–4000 m depth. The analysis of eight exploratory wells drilled in the area, has shown that the field under study presents high lateral and vertical heterogeneity, with an important connectivity uncertainty.
Geological models were performed with the objective to evaluate the structural complexity and high reservoir heterogeneity. In order to account for the properties variation uncertainty in the inter-well distribution, and the impact in upscaled models and resulting reservoir simulation, different geological model approaches were evaluated using streamline simulation, concentrating the study on some of the most important parameters that control the number of wells and recovery: reservoir quality, distribution and connectivity.
Streamline simulation allowed us to optimize the simulation grid, with the objective to capture the critical reservoir features of the fine-grid geological model. Streamline simulation can be used to analyze and rank different geological models based on certain dynamic performance parameters that effectively reflect the reservoir connectivity, which cannot be easily analyzed with finite difference simulations. The volumetric sweep efficiency and the water cut response can be used to understand the reservoir connection and heterogeneity, and the optimum level of upscaling comparing with fine-grid models.
Relatively few real field case examples of this technique have been documented in the past and this paper presents a clear workflow which helped to improve the knowledge of upscaled models screening and resulting reservoir connectivity evaluation.
Pressure Changes Effects of the Outlet Free Water Knock Out on the Oil in Water: a Case Study for Karakus Field, Adiyaman - Turkey
Authors: Ergun Ender 
Published: December 2013

Abstract
Over the past few decades, oil recovery is becoming a more significant issue. Not only in reservoirs but also in surface equipment, the loss of oil has to be degraded owing to its value. Especially, in Karakus Field, Turkey, throughout a year, more than 6,000 bbl oil is lost from just free water knock out (FWKO) which is a strikingly challenge which has to be dealt with.
Technically, due to stability of microemulsion for oil in water, the loss of oil occurs. In terms of increasing operating pressure of FWKO, entropy decreases. Thus, increments of Gibbs free energy can be supplied. Consequently, by breaking the stability of microemulsion, better quality separation can be obtained in disposal water.
This study explained that oil loss from outlet of the FWKO was attenuated by increasing pressure of vessel, while other parameters were steady such as temperature, inlet and outlet flow rate and etc. in Karakus Field. By 50 psi gradually increment of vessel pressure from 100 psi to 300 psi, quantity of oil in water from outlet of the vessel was observed at 4,300 and 6,200 bbl/day disposal water rates. By augmenting the pressure of knock out, oil in disposal water which was conveyed to injection wells reduces dramatically. According to experimental results, a significant relation as exponentially between pressure and oil in water was found. Briefly, 900 and 1,500 bbl of oil can be saved annually in order with two disposal water rates.
Dual Lateral Open Hole Coiled Tubing Acid Stimulation in Deep HPHT Sour Gas Producer Wells — Field Experience and Lessons Learned from the Ghawar Field
Authors: Al-Zaid Mustafa R. , Al-Ghazal Mohammed A. , Al-Driweesh Saad , Al-Ghurairi Fadel , Vielma Jose , Chacon Alejandro , Noguera Jose 
Published: December 2013

Abstract
In recent years, high-pressure/high temperature (HPHT) sour gas producers in Saudi Arabia, completed with two or more open hole laterals have faced several operational challenges, specifically for well intervention and stimulation procedures. Several lessons learned throughout the timeline of the operations and the procedures have evolved to optimize and enhance the results. Drilling and completing open hole multilateral gas wells in carbonate reservoirs is a common practice in Saudi Arabia to maximize reservoir contact and increase the recovery of reserves. The majority of these wells require coiled tubing (CT) conveyed acid stimulations to remove drilling damage and enhance productivity after the drilling process.
The challenging conditions encountered during the aforementioned CT interventions include: extended open hole horizontal sections with large hole diameters affecting the ability of reaching the deepest zones of interest; pumping 26% inhibited hydrochloric (HCl) acid for extended periods of time at high temperature with extremely high H2S and CO2 content, generating a very corrosive environment for all tubulars involved in the operation; wellbore instability issues inducing obstructions that prevent the accessibility to open hole sections; accessibility of alternate laterals, especially after the first lateral has been stimulated; optimum rate and pressure to achieve the desired pressure drop across hydrajetting nozzles; and natural fractured reservoirs that promote fluid losses affecting the optimum fluid placement control.
The inclusion of friction reducers for CT extended reach applications, combined with the introduction of larger outer diameter (OD) CT, have improved the access to the zones of interest. The redesign of the isolation sleeve for the jetting tool has reduced the number of required trips when obstructions have been encountered, including the improved use of steering tools to access target laterals. Further laboratory analysis, specific to the HPHT sour conditions of these wells, has been performed to minimize corrosion in the completion and the CT, and to optimize the pumping schedules to target the pay zone. This paper provides details about field experiences and lessons learned with this type of stimulation, and describes challenges faced and the engineering solutions developed to overcome them.
The Impact of LoSal™ on Oil Recovery from a Selected Carbonate Reservoir in Abu Dhabi-An Experimental Approach
Authors: Al-Attar H. H. , Mahmoud M. Y. , Zekri A. Y. , Almehaideb R. , Ghannam M. T. 
Published: December 2013

Abstract
Low-salinity water flooding LoSal™ has been used to improve oil recovery for many decades. Historically, the physical mechanism behind this improvement in oil recovery was attributed to the pressure maintenance and displacement of oil by injected water. Recently, evidence from laboratory and field tests indicated that water flooding also involves chemical processes and that modifying of the injection brine salinity and its ionic composition can significantly impact the oil recovery. Several theories regarding the mechanism of LoSal™ flooding have been discussed in the literature. These include interfacial tension reduction, wettability alteration (cation exchange), change in pH (increase), emulsion formation, and clay migration. There is no agreement, however, among the researchers regarding the mechanism of LoSal™ flooding and although limited work has been done on carbonates, some studies have concluded that LoSal™ have no effect on oil recovery.
This work presents the results of flooding tests on selected carbonate core samples taken from Bu Hasa field in Abu Dhabi using sea water and two field injection waters, Um-Eradhuma (UER) at 197,584 ppm and Simsima (SIM) at 224,987 ppm. These results were used to evaluate the effects of brine salinity and ionic composition on the possible interactions of limestone rock/ brine/ and oil system and to identify the oil recovery mechanism. The field injection waters were diluted to salinities of 5000 and 1000 ppm and the optimum salinity was determined and then modified by varying the sulfate and calcium ion concentrations. Wettability alteration was determined by contact angle measurements. Interfacial tension measurements of the studied systems were also performed in an attempt to evaluate the flow mechanism with LoSal™ flooding.
The experimental results revealed that a significant improvement in the oil recovery can be achieved through alteration of the injection water salinity. Reducing the salinity of UER water from 197,362 ppm to 5000 ppm resulted in an improvement of oil recovery from 63% to 84.5% of OOIP and the latter salinity was used to evaluate the impact of changing the sulfate and calcium ion concentrations on oil recovery. Results also indicated that sulfate concentration has a significant effect on the flooding process and that increasing the sulfate concentration beyond some optimum concentration of 47 ppm resulted in a negative effect on the flooding process. Contact angle measurements indicated that lowering the solution salinity could shift the wettability of the system towards intermediate wettability levels and that the UER water exhibits higher shift toward intermediate wettability compared to other waters. Results also indicated that there is no clear correlation between the improvements in oil recovery and interfacial tension and the pH of the studied systems.
Strategic Scope of Alternative Optimization Methods in History Matching and Prediction Workflows
Authors: Schulze-Riegert R. , Chataigner F. , Kueck N. , Pajonk O. , Baffoe J. , Ajala I. , Awofodu D. , Almuallim H. 
Published: December 2013

Abstract
Reservoir simulation workflows from history to prediction are built on a number of alternative optimization and sampling techniques with different characteristics. Adjoint techniques derive analytical sensitivities directly from the flow equations of the simulator. In a model update step those sensitivities are used for property modifications on grid cell level. Derivative-free optimization techniques like evolutionary algorithms are flexible and deliver alternative history matched cases. The propagation of reservoir uncertainties from history to prediction is often investigated using ensemble-based approaches. Markov Chain Monte Carlo and EnKF techniques are applied to generate an approximate posterior distribution as a basis for estimating prediction uncertainties.
In this work we investigate alternative optimization, sampling and data assimilation techniques with application to history matching workflows within one application framework for comparison. Validated simulation models are used for production forecast and field development planning. Methods are investigated with a focus on history matching efficiency, flexibility to integrate different types of model parameters, integration option for static and dynamic modeling workflows, capability of supporting uncertainty quantification workflows for estimating prediction uncertainties and the ability to leverage on distributed computing.
Optimization workflows are applied to a reasonably complex benchmark problem for comparison. Well production data is used in the model calibration phase and history matched simulation models are carried forward to prediction. The impact of alternative optimization concepts on estimating prediction uncertainties is discussed. This work gives an overview on alternative optimization concepts and relates capabilities, strengths and weaknesses. The impact of workflow choices on estimating prediction uncertainties is discussed. Practical conclusions are drawn for real field applications scenarios.
Rejuvenating a Mature Transition Zone Carbonate Waterflood Through Subsurface – Surface Integration: the Value of Combining Improved Subsurface Understanding While Managing Aging Facilities (Shuaiba, Sultanate of Oman)
Authors: van Koolwijk M. E. , Ghufaili A. , Warrlich G. , Goossens P. , Harris J. M. , Ogawa M. , Adhoobi A. , Hajri M. , Armstrong H. 
Published: December 2013

Abstract
This paper describes how after a period of no activity, a waterflood development is rejuvenated. This is achieved through full integration from geosciences, reservoir engineering and drilling to facilities engineering, operations and surveillance. This collaboration enabled further development following improved subsurface understanding based on appraisal, surveillance and production data as well as managing integrity and capacity issues of the aging facilities.
The Shuaiba limestone reservoir is situated in a fault-bounded, north-south trending anticline. The reservoir (~26% porosity with low matrix permeability, 1–20 mD) contains light oil (~35 API) in thin column heights of typically 5 to 30 m.
In the initial development phase the reservoir was developed by multilateral horizontal producers. Field-wide water injection started ~10 years after initial production with horizontal water injectors placed in multi-lateral patterns of up to 7 legs. The complexity is not limited to the subsurface; surface facilities handle oil-water separation from deeper reservoirs as well as 7 satellite fields.
After years without drilling activity, appraisal wells were recently drilled outside the field extent to test both structural and saturation models with the FWL progressively deepening towards the flanks by approximately ~5m tvd per km. This has added the opportunity of new flank developments to the existing field with significantly increased reserves. New insights into mobile saturation have driven the production threshold down to as low as 25% oil saturation.
The flanks will be developed with single lateral wells, taking into account the thin oil column and optimizing surveillance opportunities.
Challenges facing this development are related to maintaining the aging facilities, integrated management of flow line replacements, overall production capacity and water injection constraints. These are tackled in an integrated manner through (1) debottlenecking the main station and reducing flow line length through remote manifold stations, (2) prioritized flow line replacements ranked by surveillance activities, (3) rejuvenating the water disposal system and (4) restoring the overall downhole injectivity. These combined efforts will expand production far into the next decade.
Effect of Water Fraction on Surfactant-Stabilized Water-in-Oil Emulsion Flow Characteristics
Authors: Al-Yaari M. , Hussein I. , Al-Sarkhi A. , Abbad M. , Chang F. , Abu-Sharkh B. 
Published: December 2013

Abstract
High friction losses while pumping emulsified acid in a carbonate stimulation treatment limit the injection rate, which can negatively impact operational efficiency; consequently, reducing friction is highly desirable. This study experimentally investigates the role of dispersed phase (water) fraction on frictional drag in different pipe diameters.
Flow loop experiments were conducted to study the effect of water fraction on the flow characteristics of surfactant-stabilized water-in-oil emulsions. Emulsion physical properties such as stability, type, and rheology measurements were correlated to pressure drop measurements in a flow loop consisting of 1-in and 0.5-in horizontal pipe diameters at constant (ambient) emulsion temperature.
The results demonstrated a shear thinning behavior for the emulsions being investigated. In addition, as water fraction increased emulsion stability increased. Furthermore, a significant reduction in emulsion viscosity and pressure drop with decreasing water fraction was observed. In one case, a decrease of water volume fraction from 0.7 to 0.6 resulted in a 60 to 75% drag reduction, depending on the Reynolds number (Re). Moreover, for a given water fraction, the reduction in drag of stable water-in-oil emulsions was found to be more pronounced in smaller pipe diameter due to the shear thinning effect and became significant at higher values of water fraction and Re.
Assessing Offshore Multilateral Well Potential from the Early Life of the Well
Authors: Zorbalas K. I. , Al-Yateem K. S. , Al-Muailu H. A. 
Published: December 2013

Abstract
Operators are continuously striving to improve oil and gas field development strategies. One of the major improvements in field development strategies is enhancement of well completion designs that maximize profitability while maintaining high standards of reservoir management. Completion strategies have been transforming over the years from conventional wells to the recently drilled multilateral (ML) wells and smart wells that combine inflow control devices (ICDs) and electrical submersible pump (ESP) equipment. The new era of intelligent wells is focused on over-performing the old completion practices in terms of well productivity and reservoir sweep efficiency.
Well-A was trial tested for the first time in an offshore field by deploying a hydraulic line wet mate (HLWM) connect system with the intelligent completion (IC). This tool allows de-completing the upper completion, which includes an encapsulated (pod) ESP portion, without the need to de-complete the lower intelligent completion. The completion operation of this well consists of two stages: the first stage consists of completing the well with the intelligent completion, HLWM connect tool and a production packer. The second stage is performed by pulling the production packer by disconnecting at the HLWM point and consequently running the ESP completion while maintaining the integrity of the lower intelligent well completion in place. The completion operation in Well-A was run in two stages only to trial test the reliability of the HLWM connect system in this field, since it was utilized for the first time. In subsequent wells, the intelligent completion can be run in one stage with the ESP integrated as part of the final completion design.
A production optimization sequence utilizing a simulation model was used to analyze the potential of the well and selecting the right inflow control valve (ICV) settings from the two laterals for optimum reservoir drainage.
Detecting Changes in Permeability from Seismic Data
Authors: Wiley Robert , Wilson Peter , Peters Scott 
Published: December 2013

Abstract
Carcione and Picotti (2006) modeled the partially saturated rock case as alternating layers of gas charged permeable rocks with water charged permeable rocks and predicted there would be a velocity variation in the permeable layer versus frequency – within the seismic bandwidth. We show how these variations change with permeability. We then extend this to show variations in the reflected seismic wavelet. Finally we will demonstrate how modern Spectral Decomposition techniques can be used identify these permeability induced wave shape variations. We would point out that we are working with effective permeability which for a layer with gas will be much higher than the intrinsic permeability of a brine-filled rock.