bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Data Acquisition and Modeling for the Study of Miscible CO2 WAG in Carbonate Reservoirs Under Oil-Wet Conditions
Authors: Joubert T. , Duchenne S. , Bourgeois M. , de Loubens R. , Petitfrere M. 
Published: November 2017

Abstract
Prediction of miscible WAG performance relies on proper calibration of thermodynamical and petrophysical models. Swelling, miscibility and stripping phenomena must be captured in the equation of state (EOS) and the oscillations of gas and water saturations require using history-dependent relative permeabilities. This paper presents data synthesis and numerical interpretation of a complete experimental program including bulk PVT measurements, horizontal coreflood experiments at reservoir conditions and a spontaneous imbibition test.
Prior to flooding experiments, CO2-oil phase behavior was characterized through swelling test, slim tube, multiple contact test (MCT) and supercritical fluid extraction (SFE) to provide a reliable equation of state. Coreflood experiments were conducted using carbonate outcrop cores, carbonated water, undersaturated live oil from a Middle East field, and multiple contact miscible CO2. Produced gas and oil were experimentally separated at reservoir conditions. X-ray monitoring was carried out. The experimental data were matched using our in-house research reservoir simulator (IHRRS) and an optimization module.
We used the classical and an extended version of Larsen & Skauge relative permeabilities model, coupled to our calibrated equation of state (EOS) slightly corrected with alpha-factors to impose the residual oil saturation. Spatial variations of remaining oil were observed, with a minimum achievable oil saturation of 7 %. The condensate produced by stripping and the oil produced by mechanical sweep were matched separately. Two-dimensional simulations were performed to take into account gravity segregation, evidenced by in-situ saturations measurements. We found an acceptable history-match for each three-phase experiment individually. Significant relative permeability hysteresis was observed for both gas and water phases. Some of the three-phase parameters were found dependent on saturations path and not compatible for simultaneous history-match of multiple experiments.
This paper provides a robust methodology for miscible CO2 WAG experimental data acquisition and history match. The hypotheses and limitations of the relative permeability model were stated: for instance, trapped water saturation may be introduced. A new hysteresis model was developed allowing for water trapping, which improved the quality of the history match of the experimental observations.
Evaluation of Viscously Unstable Water Flooding with Gravity Effects and Permeability Heterogeneities Through High-Resolution Simulations
Authors: Vaillant G. , de Loubens R. 
Published: November 2017

Abstract
This paper aims at evaluating the interactions between gravity segregation and viscous fingering during water injection into viscous oils, in order to estimate the recovery factor accurately, e.g. before assessment of tertiary EOR mechanisms. Based on simulations of homogeneous and heterogeneous reservoir sector models with horizontal wells, we wish to identify the dimensionless groups affecting the water breakthrough time and the oil recovery, and to quantify the impact of viscous instabilities in 3D domains versus 2D vertical cross-sections.
High-resolution numerical simulations, based on very fine grids and a high-order spatial discretization scheme implemented in our parallel in-house research reservoir simulator, were required to properly capture the complex flow patterns of these two-phase immiscible displacements. We analyze the competition between viscous and gravity effects using different values of injection flow rate, oil viscosity, density difference between oil and water and domain aspect ratio. This analysis is carried out in 2D and 3D, for simple permeability distributions with different correlation lengths, by inspection of production data and saturation maps.
For the investigated range of parameters, capillary effects are negligible and we identify three flow regimes before water breakthrough. When gravity dominates, viscous fingering is strongly attenuated by the rapid formation of a gravity tongue but a ‘ridge instability’ phenomenon may occur. In contrast, when viscous forces are preponderant, the gravity tongue is very weak or non-existent, and the flow pattern in vertical cross-sections is often characterized by one dominant viscous finger. In the transition regime, the gravity tongue and the viscous fingers coexist and may reach the producer quasi-simultaneously, leading to an optimum injection velocity in terms of breakthrough sweep efficiency. We then examine the dependency of water breakthrough and oil recovery upon the end-point mobility ratio and the viscous-to-gravity ratio Rv/g=(μoUkvΔρg)HL. We also compare the early-time and late-time impacts of permeability heterogeneity and transverse viscous fingering.
In the context of viscous oil recovery by water injection, high-resolution simulations are required to represent the interplay between gravity segregation, viscous fingering and permeability heterogeneity. In the present study, under low capillary effects, it is quite remarkable that the post-breakthrough recovery is well predicted by 2D simulations and is mostly controlled by two dimensionless groups. This may be useful to create screening models for quick-look estimation of oil recovery on different sector models representative of an oil field.
Preserving and Securing Legacy Well Log Data
Authors: Pankaj Purohit , Fatema Al Nuaimi , Pranav Kumar , Amit Kumar 
Published: November 2017

Abstract
Well logging is the process of recording various petrophysical, properties of rock/formations penetrated by drilling tools. Log responses are functions of lithology, porosity, fluid–content and textural variation of formation. This information coupled with characteristics of sedimentary structures derived from high resolution dipmeter surveys provide detailed insight into the sedimentary environment and allows estimation of the reservoir geometry & orientations.
The Ideal approach for casing leak repairs in Old wells
Authors: Al-Dossary Abdulla Faleh , Al-warthan Abdulasalm , Al-Badran Mohammed , Al-Ghamdi Ibrahim S. , Mutawaa Wessam 
Published: November 2017

Abstract
Casing leak is one of the major reasons for wells to be worked over in oil fields. It has a negative impact on well production and might damage the productive zone depending on the leak severity, well completion configuration and well integrity. It is also detrimental to well hardware and safety. In the worst case scenario hydrocarbon reaches the surface causing an environmental spill and the well has to be plugged and abandoned. Most of the reported casing leaks occurred due to corrosion are the result of poor cement and long exposure to corrosive gases. Other reasons for casing leaks could be drill pipe wear, damaged casings owing to improper torque up practices, or wrong casing grade selection. The production wells are to be drilled and completed with the intent to pump hydrocarbons for the longest possible period of time before any work over (WO) is due. Casing leaks could occur in the course of drilling operations or after completion time. There are two types of casing leaks encountered during work over operations: two-way and one-way leaks (dumping or taking) depending on direction of flow, cement integrity and formation characteristics behind the casing. The first example is seen mostly across shallow aquifers that have sour gas and are difficult to cement due to incurable losses. The second example occurs across highly over pressurized corrosive water bearing zones that are tight and underlying, or overlying high permeable zones, making cementing the annulus difficult and causing potential leaks. The WO team has come up with an effective approach for each type of leak that is time saving and cost-effective, and provides a long lasting solution. Also, drilling and cementing practices in fields where casing leaks occur have been revisited to prolong the life of wells. This paper explains all types of leaks and their consequences. In addition, it highlights the circumstances that accompany casing leaks and provides an analysis tool for best casing leak repair approach based on a thorough in depth statistical study.
A New Thermally Stable Synthetic Polymer for Harsh Conditions of Middle East Reservoirs. Part I. Thermal Stability and Injection in Carbonate Cores.
Authors: Dupuis Guillaume , Antignard Sebastien , Giovannetti Bruno , Gaillard Nicolas , Jouenne Stephane , Bourdarot Gilles , Morel Danielle , Zaitoun Alain 
Published: November 2017

Abstract
A great number of Middle East fields have too harsh reservoir conditions (high temperature, high salinity) for conventional EOR polymers used as mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable.
At temperatures above 70°C, acrylamide moieties hydrolyze to acrylate groups which ultimately may lead to precipitation and total loss of viscosifying power. Thermal stability can be improved by incorporating specific monomers such as ATBS or NVP. However, their polymerization reactivity can cause some compositional drift and limit their molecular weight / viscosifying power. Compared to HPAM, they will require a higher dosage and higher cost.
In this study, we present thermal stability and propagation behavior of a new class of synthetic polymers with high thermal stability. In harsh conditions of Middle East brines, with salinity ranging from sea water to 220 g/L TDS, they present excellent thermal stability until temperature as high as 140°C. Adsorption and mobility reduction were evaluated through coreflood experiments using carbonate cores and Clashach sandstone cores, with permeability ranging between 100mD and 700mD. Mobility and permeability reductions indicate a good propagation in both types of rocks.
The development of this new polymer is a major breakthrough to overcome the current limits of polymer EOR applications in harsh reservoir conditions. Moreover, molecular weights can be tailored from low to high molecular weights depending on reservoir permeability. Further work is needed to evaluate resistance to mechanical degradation, salt tolerance and adsorption in carbonates and sandstones.
Real Gas Lift Optimization: An Alternative to Timer Based Intermittent Gas Lift
Authors: Moffett R. E. , Seale S. R. 
Published: November 2017

Abstract
A simple electronic control method for automatically determining the "on-time" parameter for intermittent gas lifted wells using existing continuous gas lift valves is presented. Lift gas consumption and production during intermittent operation is compared to previous continuous gas lift results of the same wells in an unconventional reservoir. Performance during abnormal field conditions is analyzed. Interpretation of pressure/flow curves is explained.
Algorithms in electronic controllers normally used for plunger lift optimization are adapted to intermittent gas lift. Several pressure and flow phenomenon indicate the stage of the intermittent gas lift cycle. The most important indicator is a sudden increase in tubing pressure and gas production rate which signifies the arrival of fluid at the surface of the well. A setpoint is used to determine that the fluid slug has arrived and the gas injection is then brought to a halt until a timer or other parameter determines the beginning of the next injection cycle.
Nearly all wells which were tested with the new control algorithm showed a large drop in consumption of lift gas, which was the only target of the test. The wells which showed the greatest lift efficiency improvements produced on average less than 150 barrels of total fluid per day. Many wells may have been producing less fluid under continuous gas lift due to higher average bottomhole pressure under continuous injection conditions. Nearly all wells maintained or increased production after the change. The use of an automatic on-time adjustment maintained production under scenarios where strict timer-based systems would have failed to produce fluid. The amount of time needed to restart a well after an automatic shut-in was reduced by closing the gas lift injection valve when a flow obstruction was indicated by rising tubing pressure and automatically restarting the well when conditions improved.
This method is a simplified control strategy which can be implemented and maintained with little user intervention. Practicing engineers responsible for optimizing large groups of wells may find value in this novel strategy. The shale operator received a ROI of 7 days using this new approach.
High-Density Surveillance in a Supergiant Field: Integrating Clastic Sedimentology With Dynamic Data in a Mature Asset
Authors: Jude E. , Wells M. , Brown R. , Camplin D. 
Published: November 2017

Abstract
The Main Pay reservoir of the supergiant Rumaila oil field in southeast Iraq has been on production since 1953, and is now in a mature production phase. An onshore field of this scale and longevity is in a rare position to benefit from large volumes of high density dynamic data, including repeat cased hole saturation logs, formation pressure data and production logging tool runs. In mature field life these data are beginning to highlight complex reservoir behaviour, not fully captured in previous subsurface descriptions.
Water Shut - Off Treatments in Oilfield by Micro and Nano Technology: A Good Way to get More Oil and Less Water.
Authors: Casalini A. , Lima R. 
Published: November 2017

Abstract
It has been developed a novel chemical based water shut-off technology for reducing water cut and increase crude oil production in mature fields.
This technology employs polymeric gel beads (micron size range) suspendend in an organic solvent, hereinafter referred to as SMART W, which can swell selectively in contact with formation water and remain stable in contact with crude oil. Then an interconnected network of swollen particle can be generated in situ exclusively inside the water rich pattern. A proper amount of this gel can be able to plug water inflow pattern, even fracture or high permeability paths originated, while the crude oil filled fractures or paths continue to produce as before treatment. Gels beads dimensions can be properly chosen to act on water coming from fractures or high permeability paths and can be applied by means of common bullheading procedures and equipment.
This is of outmost importance if wells are not able to produce in natural flow, like those that are producing by Sucker Rod Pump or other similar crude oil lifting system, then reducing water will increase crude oil production by same extent. In this way is then possible to increase estimated recoverable reserves or reduce investment cost to access to such reserves, infact water production is a major problem that affects all wells and, in some context, can cause the premature shut-in of the well itself. Finally reduction of produced water is anyway important with consequential advantages in terms of i) corrosion, ii) bacterial growth, iii) scale deposition, iv) sand production and more in general has a positive impact on oil center facilities overall treatment capacity.
SMART W had been succesfully evaluated first at laboratory scale and then with several field trials in order to demonstrate the effectiveness and the significant benefits in terms of water/oil ratio. In addition, this technology has also been proven satisfactory in terms of duration of treatments effectiveness and selectivity. No any adverse effect has been expected or detected on oil center facilities. Versalis S.p.A. succeeded in scaling up the formulation of a microgel polymer to industrial level in order to have it available in industrial quantities.
Skill Development Tool to Build Future Petro-Technical Professionals
Authors: Al Hadhrami Ayesha , Kumar Pranav , Saleh Nawal Eisa , Alnaqbi Manahel Mohamed , Jaradat Amin , Bamatraf Majdi Mohamed 
Published: November 2017

Abstract
Success of any company depends on the ways its employees are developed. The ability and performance of the professionals play an important role. Emiratization department of ADCO has been working on developing the Fresh Graduates to a Professional Petro-technical expert over the years. This paper will focus on explaining the methodology and techniques used in the Graduate Development Program (GDP). Results of the GDP shown in the paper will prove the success of the GDP. Measurement of GDP success is achieved with set of metrics involving standard procedures, progress, communication, reporting, assessment & development. The performance of a GDP is measured with level as Awareness, Knowledge and Skills. The competencies on which GDP is assessed are based on Core, support, general and behavioral elements. Line Manager, Supervisor, Coach, Mentor, assessors and Verifier are roles played by senior employees in developing a GDP. There are other parameters which help a GDP to move from Entry point level to a core position after finishing 100% from the core elements. Implementation and validation of the GDP is calculated from the assessment process. Assignments are given to GDP employees on the basis of Awareness, Knowledge, and Skill, which the Entry Point employees have to complete during their development period. These levels have different elements which can be a Question, Observation and Product from the business. All the levels of the element are approved by supervisor, who also assesses the real work activities performed by GDP. Progress of GDP is done from entry level to an independent position.
The methodology and calculation devised in the GDP can be useful for other Oil and Gas companies to develop the Graduate employees to experience level. This is in line with the nationalization policies that various companies are following. This paper has explained the methods and processes used to develop a fresh graduate to a next generation Petro-technical professional.
Deepwater MPD Operation and Design Method
Authors: Kuroda Y. , Kudo H. , Toyoda K. 
Published: November 2017

Abstract
INPEX Offshore North West Sabah, LTD. has committed to drill two deepwater exploration wells in water depth upto greater than 1,000m offshore Sabah in East Malaysia. The typical deepwater wells, due to narrow drilling window between pore pressure and fracture gradient, require multiple CSG strings to reach total depth. Because of the uncertainty in pore pressure and fracture gradient prediction, which causes pressure-related well control problems, the initial CSG design with conventional method was conservative and highly costly design.
Managed Pressure Drilling (MPD) with Constant Bottom Hole Pressure (CBHP) mode enables the development of an adaptive well design and safe operation by providing the following key points: Improved Kick ToleranceEarly Kick Detection by Coriolis Meter can reduce influx volume. Once MPD system detects the influx in "auto mode", the system automatically increases back-pressure to stop the flow while drilling. Typical influx in MPD mode is less than 3 bbls.Improved Safety and Well ControlIt mitigates the risk of exceeding MAASP with MPD because of smaller influx. Also it can enhance ability to safely circulate out gas in the riser.ECD ManagementIt enables to maintain the constant bottom hole pressure during drilling and connection. Adjusting MPD choke can manage the drilling safety margin.
MPD application with the adaptive CSG design will most likely eliminate at least one CSG, and has potential saving of two CSG strings, which represents significant cost saving.
The method introduced here is applicable to any deepwater well which has narrow drilling window. MPD application with Below Tension Ring RCD (Rotating Control Device) on 6th generation dynamic positioning rig can develop real time CSG setting depth optimization with the management of bottom hole pressure in each hole section.
Engineered Fit-For-Purpose Cement System to Withstand Life-Of-The-Well Pressure and Temperature Cycling
Authors: Al-Yami Abdullah S. , Wagle Vikrant B. , Abdurrahman Riefky , Taoutaou Salim 
Published: November 2017

Abstract
Due to pressure and temperature changes during the life of the well (from drilling to production); globally many Casing-Casing Annular (CCA) leaks are observed in the annuli between surface and intermediate casings. A new approach to well cementing had to be developed, and advanced cement technologies considered, taking into account both short and long term design parameters.
To assess the effect of pressure and temperature cycling on the long-term well integrity, finite element modeling of sections of interest was performed to analyze the stresses applied on the cement sheath throughout the life of the well. Such modeling requires detailed knowledge of the pressure and temperature cycles, as well as the mechanical properties of the formations, casings and cement.
The output is a failure analysis of the cement sheath in terms of compression, tension and micro annulus development. Once the failure mechanisms are well understood, further sensitivity analyses permit to select the most adequate cement system for the application, based on target windows of compressive and tensile strengths, Young's modulus, Poisson's Ratio, and expansion capacity.
The paper will discuss a case study where a fit-for-purpose durable cement system was designed to meet the required mechanical properties as suggested by the stress modeling performed on a candidate well. It was placed as a Tail slurry on the 9 5/8" Tieback casing to provide 1000 ft. of long-term hydraulic isolation in the cased annulus should the liner top packer fail to seal the high-pressure water formation below. A post-job analysis using job data and cement evaluation logs showed that placement was executed as per design and that the durable cement system provided excellent bonding and annular coverage. The well was later drilled to total depth, completed, fractured and delivered to production without CCA pressure at the wellhead.
The new approach consists of performing finite elements stress modeling during the well planning phase to custom design cement systems that will withstand the anticipated loads.