bluuebunny/crossref_metadata_2025_split huggingface dataset:
Polymer Distribution Concepts for Large Scale Polymer Floods in the Sultanate of Oman: Simplicity or Flexibility?
Authors: Al Baqlani Safa , Singh Suresh Kumar , Glasbergen Gerard , van Elk Harry 
Published: March 2018

Abstract
Enhanced Oil Recovery (EOR) is firmly established in the hydrocarbon maturation plans of PDO and Shell. Particularly polymer flooding is a proven and established method for hydrocarbon recovery. An important step in maturing polymer flood implementation is the upscaling from a successful pilot to field scale. One of the elements in the upscaling process is the distribution of polymer solution to the different polymer injectors. A fundamental choice is whether flexibility in operations is required to optimize the Well Reservoir and Facilities Management (WRFM) of a polymer flood or the simplest surface concept should be selected. This paper describes the rationale for making a choice for a distribution concept.
The current experience in polymer flooding shows that the value of having WRFM capabilities is substantial. In this paper we evaluate the value of WRFM regarding polymer injection. Choices such as the need for varying polymer concentrations per injector and changing the duration of a polymer injection scheme are evaluated. The impact of the regrets for not having the ability to manage the polymer injection are quantified and the probability on the necessity of these aspects of WRFM in a large-scale field is determined based on the experience in an ongoing polymer flood in the South of Sultanate of Oman. Examples are shared that underpin the variance in response form pattern to pattern. Besides the value of WRFM capability, a large number of different concepts for polymer distribution are evaluated based on value, costs and feasibility of implementation and operation. Yard tests were performed to quantify the effect of mechanical shear degradation of low and high concentration polymer to underpin eventual value loss of the polymer.
The value of having WRFM capabilities in a polymer flood is clearly articulated and confirmed from the analysis of polymer field data. Large pattern by pattern variations in polymer injectivity and polymer upsides will lead to the decision that the flexibility to turn of polymer injection and reverting to water injection in some injectors is a necessity. A new concept that combines flexibility and simplicity with limited number of moving parts has proven to be feasible and cost effective. The feasibility of the concept is articulated by the positive results of yard tests that show that high concentrations polymer solutions have limited shear degradation.
Upscaling from pilot to field scale EOR flood is complex. The structured and integrated approach using both surface and subsurface capabilities combined with actual field performance data and supporting experimental data is novel. The limited amount of shear degradation of a mother solution opens a large number of additional concepts that combine simplicity and flexibility. The concept is not only applicable for onshore fields but also enables implementation of polymer flood in an offshore subsea environment.
Super Critical CO2 and Steam Co-Injection Process for Deep Extra-Heavy Oil Reservoir
Authors: Erpeng Guo , Yongrong Gao , Youwei Jiang , Yunjun Zhang , Zhigang Chen , Yao Wei 
Published: March 2018

Abstract
Thermal recovery process is widely adopted in exploitation of heavy oil reservoirs. But for extra-heavy oil reservoirs with bottom water and depth more than 800m, effective recovery is not achieved with steam injection. SAGD (Steam assisted Gravity Drainage) process is tested in such reservoirs but showed poor performance because of high reservoir pressure and bottom water. This paper proposed a new approach which is utilizing super critical hydrocarbon gas to replace most part of steam during steam injection and SAGD process for exploitation of such reservoirs.
Calculations of heat distribution along the steam injection tube were carried out. The solubility of supercritical hydrocarbon gas in heavy oil was tested with PVT apparatus. Also the viscosity reduction effect of super critical gas is also tested. SAGD simulation with high mole percent of gas injection was carried out with theoritical model. Different operation strategy including pure steam, supercritical CO2 and steam co-injection, wet gas and steam co-injection was compared with numerical simulation.
The main theory of this approach is that injected gas can greatly decrease partial pressure of steam hence reduce the heat loss and drawdown of quality during injection. The results shows that the heat loss can be decreased by 40% in steam injection tubing. At super critical conditions, solubility of gas in heavy oil is almost 100m3/m3. Viscosity of heavy oil saturated with gas will be lower than 200mPa.s at 150℃which is 80% less than that without gas. The viscosity is already low enough for drainage process. High pressure SAGD experiment shows that temperature decreases gradually from the inner part to the out range of steam chamber when injected mole percent of gas is 20%. This means the decrease of steam saturation pressure related to partial pressure of steam because injected gas will take the corresponding pressure in steam chamber. The recovery process shows high recovery factor which is similar to SAGD process. And steam oil ratio is 0.8~1.2 which is much lower than any existing pure steam injection SAGD process. Simulation results shows that during the operation process bottom water will not flux into steam chamber after the balance between reservoir and bottom water was achieved.
This paper provides an effective approach to exploit the heavy oil reserves with great depth which is meaningful for reducing the steam consumption and operation cost for oil industry.
Surfactant Selection for Chemical Flooding of Very Low Salinity Reservoirs – An Underrated Challenge
Authors: Jakobs-Sauter Britta , Rommerskirchen Renke 
Published: March 2018

Abstract
Recently, research and development of EOR surfactants focused on so-called "harsh" conditions like e.g. high salinity reservoirs combined with high temperatures. It is well known and acknowledged that dealing with large amounts of dissolved electrolytes in the injection brine causes difficulties for most types of surfactants and other chemicals. Mostly overseen is the fact that, especially for surfactants, very low salinity conditions can also be quite challenging. We present a comprehensive phase behavior study based on the fundamentals of surfactant science.
Surfactant flooding has highest efficiency when a surfactant is chosen whose optimum conditions match the reservoir parameters. The phase behavior of the injected surfactant slug and the crude oil depends strongly on temperature and water salinity, which directly influence the ability to reduce the interfacial tension. Near-fresh water injection brines do not have major precipitation issues, but they require surfactants of certain hydrophobicity. This is caused by the fact that decreasing salinity at constant temperature favors the interaction of the surfactant with the aqueous phase and increases its water solubility. In order to counterbalance the preference for the aqueous phase the hydrophobicity of the surfactant has to be increased to force the formation of a microemulsion middle phase. By this procedure the water – surfactant – crude oil interaction is adjusted, resulting in Winsor III type phase behavior and the desired ultra-low interfacial tension regime. However, increasing the surfactant hydrophobicity decreases its water solubility. This can disturb its transport within the injection water towards the crude oil in the formation.
Our results provide a good overview of the challenges and advantages in the application of amphiphilic compounds at low salinity. The water solubility and the phase behavior of different classes of surfactants and their blends are shown. Several approaches are investigated to overcome these challenges or find ways to deal with them. The perils of blending surfactants are addressed and the question is posed how the appearance of the injection solution affects its performance.
In the light of a growing interest in smart-water flooding technology the salinity in mature reservoirs is expected to drop significantly. This paper compares different approaches for the selection of appropriate surfactants when dealing with very low saline waters. To not impede the application of surfactants in a later stage of the reservoir life cycle and to achieve maximized outcome it has to be planned carefully if a smart-water flood shall be applied.
Increasing Value through Digital Transformation; A Case Study from the A Field Thermal EOR Asset, Sultanate of Oman
Authors: Holyoak S. , Alwazeer A. , Choudhury S. , Sawafi M. , Belghache A. , Aulaqi T. , Bahri S. , Yazidi R. , Yahyai A. , D'Amours K. 
Published: March 2018

Abstract

Context and Objectives
Petroleum Development Oman's "A" Field Thermal Asset, southern Sultanate of Oman, is characterized by a large scale Steam Drive/Cyclic Steam Soak (CSS) development project, underpinned by extensive data gathering. Cambrian faulted/fractured braided river sandstones are the predominant reservoir, with &lt; 300m of heavy oil. Viscosity is high, reaching up to 400,000 cPAt around 1100m tvd, the reservoir is relatively deep for a thermal project.Well count is high, and steadily increasing.
These factors create a challenging environment for maximising oil recovery. Key to success is efficient execution of data management and analysis, within a visualization intensive, collaborative work environment. In this paper we aim to demonstrate that working in this manner, within a cross-discipline asset environment enables the rapid identification and execution of cost-effective optimization opportunities and risk reduction.

Approach
In order to provide a sufficiently broad description of how the Asset is working towards the desired outcome, the paper addresses the following elements:- Data Capture, Transmission and Storage.Application of original algorithms and tools to convert the data into meaningful insights.Accessibility to insights (speed and mode of access).Meaningful impact to efficiency, production, and safety.Added value associated with the implementation.

Results to Date
Some of the areas further discussed include the following:- Implementation of Automatic Beam-Pump Optimisation has resulted in step-changes in terms of both oil production and reduced manpower requirements.Distributed Temperature Sensing (DTS) wells are providing real-time temperature profiles, essential for monitoring steam conformance.Automated well tests are fully operational in "A" East Field, and the results can be viewed and analysed via desktop applications in the Asset.6 Micro-Seismic wells have been successfully executed and now provide real time monitoring of reservoir integrity.A live subsurface model has been developed, which can be rapidly updated with new drilling results and subsurface insights.
The above elements are continuously facilitating asset management, whilst also highlighting opportunities and reducing uncertainty as we follow the data journey from scoping and capture through to bottom line impact.
Temperature Dependant Relative Permeabilities End-Points: Laboratory Experiments under Reservoir Conditions from Hot-Water Flood to Steamflood
Authors: Lamy C. , Botua J. , Granone U. , Hy-Billiot J. , Brisset A. 
Published: March 2018

Abstract
Recovering heavy or viscous oils is always a challenge. If the reservoirs are deep, mining is not possible. SAGD, a very well known in-situ recovery steam process is a very efficient method. By injecting steam in the reservoir, the oil is heated, decreasing its viscosity, modifying wettability and thus making it flow more easily. Relative permeability equations are key to be able to modelize the SAGD process and to determine the best optimization parameters (for a better energy efficiency and potentially reduce costs linked to this thermal EOR process). There are very few laboratory experiments (Quettier, 1988; Schembre, 2005; Nakornthap, 1986; Maini, 1985; Kovscek, 2014) in the literature about relative permeability changes with temperature.
This paper describes the results of the 5 laboratory experiments performed on porous medium (unconsolidated sand) with extra-heavy oil at reservoir conditions by injecting hot water or steam. Experiments are made in reconstituted cores of 50cm long and 5 cm of diameter, with the sand and the oil from a specific field. The isothermal hot water injection experiments have been done at 36 bars, and 60°C, 120°C, 180°C and 240°C. Steam injection experiment has been done at 36bars, 245°C in a core initially at 36bars, 60°C. This report explains the different steps of the experiments, the conditioning and the procedure. Results are analyzed and interpreted to give end points data and identify the production mechanisms for each coreflood. Experimental parameters have been acquired accurately and data check has been done carefully.
Swi values increase with temperature; Sor has a lower value for 180°C than for other temperatures. An optimum of production in liquid waterflooding has been observed for this experiment (+10% compared to isothermal experiment at 120°C and 240°C), and a recovery after 20 PV comparable to the one of the steam injection experiment after 3 PV. This kind of behavior has already been published in literature and is often linked to change of wettablity with temperature (Maini, 1985; Kovscek, 2014; Jadhunandan, 1995). To confirm this behavior, the same experiment could be reproduced.
Steam injection shows the best efficiency, with a fast recovery: 77% in less than 0.7 PV injected and a final recovery of 80%.
These experiments allow a better understanding of hot-water and steam displacement mechanisms and provide Swi, Sor, Kw, Ko, RF changes with temperature. They can be used to improve the modeling of steam based processes as SAGD.
Thermal Performance Challenges and Prospectives of the Russian Largest Carbonate Reservoir with Heavy Oil
Authors: Ursegov Stanislav , Taraskin Evgenii , Zakharian Armen 
Published: March 2018

Abstract
In carbonate reservoirs with heavy oil, the implementation of "classical" thermal EOR methods such as cyclic steam stimulations, steamflooding, and steam assisted gravity drainage usually demonstrates a lower efficiency in comparison with sandstones. The key performance problems are a very complicated porous structure of carbonates represented by matrix blocks, fractures, and vuggs, and a negative wettability of carbonate rocks, which remains mostly oil-wet even with heating. These suggestions are fully confirmed by actual and laboratory results of the Permian - Carboniferous reservoir of the Usinsk field located in Northwest European Russia. The reservoir has the largest heavy oil remaining reserves in the carbonate reservoirs of Russia. Since the viscosity of its oil is more than 700 mPa*s, in some areas of the reservoir, there is a steam injection at ~300°C and ~10 MPa, which are being used for 25 years via vertical and horizontal wells. However, the current oil recovery numbers of the pilots are estimated only between 12 and 15 %. This work includes the analysis the results of recently conducted experimental studies with stacked core models and the actual production and injection data of the thermal pilots with different well configurations.
Application of Water Swelling Polymer to Reduce Vugular Zones Using Emulsified Diesel as Carrier Fluid
Authors: Varshney Mayank , Goyal Aman , Jain Akanksha , Pandey Nimish , Parasher Arunabh , Vermani Sanjeev , Singh Aman , Deshpande Mayur , Pande Karan 
Published: March 2018

Abstract
Injection of fluids continuously into the reservoir at higher flow rates can create channels for preferential movement of fluids. Zones of higher permeability, leading to higher injectivity in selective zones, can also exist because of various lithological conditions and rock structures comprising of naturally occurring fractures or fissures (Vasquez et.al. 2008). For injection wells, the entry of fluids into a set of perforation interval is governed by the quality of the perforations and the permeability of the formation at that depth. Preferential flow of injected fluids into a selective set of perforation interval results in diminished overall sweep efficiency. Water Swelling Polymers (WSP) have proved to be effective in shutting off the thief/vugular zones and thus diverting the injected fluids in the reservoir matrix. WSP swells multiple times of its original size once it comes in contact with water and thus reduces the flow area available in the thief/vugular zones.
This paper discusses a case study of the use of water swelling polymers (WSP) to shut off thief zones in an injector well. The operational aspects along with the associated methods and challenges are discussed. The selection of carrier fluid for the WSP was one of the biggest challenges. Diesel as a carrier fluid would have increased the chances of WSP settling due to its low carrying capacity, leading to an increase in tubing pressures, potential choking of pump valves, and an improper placement of treatment fluid. Water has a higher carrying capacity but would have led to premature swelling of WSP. Hence, the treatment fluid selected was an oil external emulsion of diesel and water. This enhanced the carrying capacity of the treatment fluid without leading to pre-mature swelling of WSP.
The treatment was pumped with alternate stages of WSP with carrier fluid followed by 5% KCl solution to swell WSP in the formation. Pressure increase was observed with every subsequent WSP stage, which indicated the effectiveness of the treatment. Post-job injectivity data and MPLT confirmed a considerable reduction in injectivity index, indicating placement of WSP across the desired zone.
The treatment was pumped at lower rates than expected, but no WSP settling was observed in surface lines. In a post-treatment cleanout stage, some WSP from the sump of the well was collected and found to have sufficiently swollen as designed. No settled WSP was observed in the coil, pump, or surface lines upon rig down.
The use of emulsified diesel as a carrier fluid was implemented for the first time in India. Coil Tubing (CT) was used for effective placement of WSP. The combination of emulsified diesel and CT resulted in reducing the probability of WSP settling in wellbore and pumps, which improved the economic efficiency of the job by eliminating cleanup and pump valve replacement time.
Evaluation of Early-Time Reservoir Response for a Thermal Pilot in Kuwait
Authors: Bagheri M. , Al-Otaibi M. , Al-Naqi Y. , Al-Ballam S. , Boqrais A. , Peydayesh M. 
Published: March 2018

Abstract
To realize the potential of heavy oil assets in achieving the long term production targets of Kuwait Oil Company (KOC), various pilots are currently under operation. This paper provides an overview of a recent multi-pattern pilot under steam injection to evaluate reservoir potential and to reduce the uncertainties in future investments. The implementation of a comprehensive surveillance plan is described and the early results of the pilot are discussed.
Analytical techniques, statistical methods and engineering tools have been implemented to understand the reservoir performance and to evaluate operational variables. These techniques include injectivity analysis, pressure transient analysis, and multivariate analysis of production data.
The size of steam chest is estimated by indirect techniques such as pressure fall off test which have been qualitatively confirmed by analytical methods. The analysis includes integration with other techniques such as seismic data and Distributed Temperature Sensing (DTS) in observation wells. Modified Hall plots for steam injection were used to evaluate the possibility of formation parting, where further insight was gained from interpretation of anomalous signatures in the modified Hall plots for some wells. It is also shown that the impact of steam injection volume on reservoir response could be better understood by multivariate statistical analysis where numerous parameters influence the results.
This work presents the early results and shares the experience of operating a thermal pilot in the Middle East where limited thermal heavy oil operations exist.
Well and Reservoir Surveillance Challenges Based on MGI and GI Experience
Authors: Dmitrii Smirnov , Aisha Sariri , Mutasem Abri Al , Tushar Narwal , Fakhriya Shuaibi , Riyami Yaqoob , Zahir Abri , Al-Hadhrami Abdullah , AL-Yaarubi Azzan Hamed , Habsi Yumna Rashid 
Published: March 2018

Abstract
In the past 20 years, there has been a string of exploration successes in newly discovered oil-bearing carbonate reservoirs within the South Oman Ara salt basin. These oil reservoirs are deep (3000–5000 m), encased by salt, and have high reservoir pressure far above the hydrostatic gradient. The crude is light (30–45 API gravity) and contains 5–17% CO2 and 2–6% H2S. Reservoir properties are relatively poor: average porosity varies from 5 to 10%, and permeability varies from one to several tens millidarcy. The primary recovery mechanism is pressure depletion, with low recovery in the range of 4–8%.
Enhanced oil recovery (EOR) by means of immiscible gas injection (GI) was implemented in Field-B in 1993, and miscible gas injection (MGI) was started in Field-Z in 2012. The MGI program is expected to increase the ultimate recovery up to 45%. The main subsurface risks to the performance of the gas injection projects include vertical and areal conformance, gas breakthrough, and reservoir pressure decline. The key objective of the MGI surveillance is to establish residual oil saturation in gas-flooded rock. The key issues and challenges for the surveillance include low porosity, complex drilling operations, well design, and completion.
The well and reservoir surveillance management (WRM) activities included the drilling of a dedicated monitoring well, collection of various pressure measurements, injection of tracers, and acquisition of advanced openhole and casedhole data, which included nuclear magnetic resonance (NMR), pulsed neutron logging (PNC), and production logging (PL). The primary focus of this active WRM plan is to monitor the performance of the GI and MGI. The plan has been successfully implemented.
We present examples of reservoir surveillance data, such as the molecular diffusion-sensitive NMR and enhanced PNC data acquired in Field-B and Field-Z. The objectives of these measurements are to monitor the current oil saturation and detect and evaluate gas breakthrough. The static downhole pressure survey and formation pressure measurements were collected in newly-drilled infill wells. The PL and tracer survey data effectively provided information about gas breakthrough intervals and enhanced the understanding of the impact of vertical and lateral heterogeneity. This data is also useful for planning gas shutoff when the breakthrough is detected.
The applied surveillance strategy supports Field-Z and Field-B gas injection performance. The strategy can potentially benefit other analogue fields undergoing similar development options to reduce subsurface risks, proactively recognize problems, and devise effective mitigation actions.