bluuebunny/crossref_metadata_2025 huggingface dataset:
The Role of Synthetic Polymer on Rock-Fluid Interactions and the Resulting Change in Ionic Composition and Viscosity of the Polymer Slug for a cEOR Flood in the Sultanate of Oman
Authors: Berge A. B. , Lenchenkov N. , Wever D. A. , Farajzadeh R. , Al-Mjeni R. , Glasbergen G.
Published: March 2018

Low salinity polymer (LSP), in which the salinity of the make-up water is significantly lower than of the formation water, is an attractive alternative to conventional polymer flooding because of the reduced amount of polymer required. Viscosity loss due to cation exchange with the rock surface however is a significant risk. In this paper, the influence of partially hydrolyzed polyacrylamide (HPAM) polymer on the rock-fluid interactions has been studied by analyzing produced fluids of several core flooding experiments. It was found that all produced fluids containing polymer show elevated levels of divalent cations (mainly Ca2+ and Mg2+) compared to the produced fluids of slugs of brine injected without polymer. This was observed for both high (formation water) and low salinity polymer solutions. The divalent cation levels typically remain elevated for at least several pore volumes of polymer injection. Additionally, produced water from a field on polymer flood was found to contain elevated levels of divalent cations as well.

These results confirm that polymer affects the rock-brine equilibrium and tends to attract divalent cations, which are provided by the rock surface. In our experimental results, the concentration of divalent cations could increase by as much as a factor of 5 compared to the equilibrated brine. The expected viscosity loss varied from no loss (even for LSP) to a loss of ~30%. The extent of cation exchange and viscosity loss strongly depends on the rock-fluid system, in which the charge ratio (CR) of positive charges on the divalent cations in the solution to negative charges on the polymer as well as the divalent to monovalent cation mass-action-ratio (MAR) appear to be important and predicting parameters.
In-Situ Microemulsion-Assisted Fluid Recovery with Blend of Anionic-Cationic Surfactants in Super High Temperature-Extra Low Permeability Formations
Authors: Li Yingcheng , Li Qiang , Zhang Weidong , Meng Yong , Jin Jun , Bao Xinning , Sha Ou , Shen Zhiqin , Yang Yiqing
Published: March 2018

The main challenges for extra low permeability reservoir are injectivity decline and high tubing head pressure (THP) which caused the decreases in hydrocarbon production. The most common causes of deterioration in the reservoir permeability and formation damage include the buildup of in-situ emulsions due to crude oil interaction with drilling and completion fluids, water blockage, asphaltene and paraffin deposition and alteration of near-wellbore wettability. In new wells, near-wellbore formation damage may be caused by emulsion blockages when the whole mud, mud filtrate or completion fluids interact with the formation fluids.

Traditional chemical treatments have been widely used to remediate damaged formations for removal of non-aqueous fluid. Various approaches to tackle this problem have been adopted. For example, acid, solvents and mutual solvents have been applied to improve the reservoir permeability, with varying degrees of effectiveness. Microemulsion fluids with unique propertie such as an ultra-low interfacial tension (IFT), high solvency and compatibility with formation fluids has received great interests and shows great potential to effectively remove emulsion blockages, remove precipitated crude oil macromolecules, and reverse wettability to enhance hydrocarbon production.

In this paper a new in-situ microemulsion formulation consisting of blend of anionic-cationic surfactants (Sa/c) has been developed to assist the fluid recovery for extra low permeability reservoir at dilute concentrations. Ultra low IFT of 3×10−4 mN/m, solubilization parameters of 18, and ultra low critical micelle concentration of 6.8 mg/L were obtained. Freezing point of crude oil was decreased by 18%, together along with 84.5% viscosity reduction by formation of microemulsion. In addition, wettability alteration was also observed.

Lab data shows that the in-situ microemulsion is highly effective in fluid recovery and relative permeability enhancement when applied in stimulation treatments at dilute concentrations.

Filed test by using in-situ microemulsion-assisted fluid recovery with Sa/c was tested in super high temperature-extra low permeability formations (reservoir temperature: 116°C, permeability: 4.5 mD) to demonstrate how this novel technology can significantly enhance hydrocarbon production in poorly producing wells.
Enhancing Oil Recovery from Dolomitic Reservoirs- Investigation of Temperature Limitations
Authors: Puntervold Tina , Strand Skule , Torrijos Iván D. , Hopkins Paul , Austad Tor
Published: March 2018

EOR by Smart Water injection in calcite, CaCO3, is dependent on factors like initial wetting, injection brine composition and temperature. Because of the chemical difference between CaCO3 and dolomite, CaMg(CO3)2, the relationship between EOR effects and the above-mentioned factors could be different. Smart Water EOR potential was experimentally tested for two dolomitic reservoir systems, at low and high reservoir temperature, to determine if there was a temperature limitation for observing EOR effects by Smart Water injection.

Oil recovery tests by spontaneous and forced imbibition experiments were performed to evaluate initial wetting and wettability alteration from two dolomitic reservoir systems. A fractured reservoir system at 65 °C was investigated by spontaneous imbibition tests, while a non-fractured system at 115 °C was investigated by forced imbibition tests. The reservoir cores were saturated with their respective formation waters and crude oil, then imbibed with diluted seawater or modified seawater brines. Oil recovery responses at the different temperatures and by using different imbibing brines were evaluated and compared.

Spontaneous imbibition tests, performed in the fractured reservoir system, showed that a diluted seawater brine increased the oil recovery from the dolomitic core material at 65 °C. When a modified seawater brine, which is a Smart Water for CaCO3, was used, there was no EOR effect observed. Forced imbibition tests with diluted seawater brine showed increased oil recovery for a non-fractured dolomitic reservoir system at 115 °C, while a modified seawater resulted in no extra oil produced.

The results showed that there was no temperature limitation for observing EOR effects in dolomitic reservoir core material within the temperature range 65 - 115 °C. It was confirmed that diluted seawater brines altered the initial core wettability towards more water-wet conditions and enhanced oil recovery was observed both in spontaneous imbibition and forced imbibition experiments. Due to the differences in mineralogy between CaCO3 and dolomite, CaMg(CO3)2, and in their chemical reactivity, the optimal injection water, i.e. Smart Water compositions, were different.

Smart Water EOR effects by wettability alteration in dolomitic reservoir material were observed both at low and high reservoir temperatures. The final oil recovery was dependent on the injection brine composition. Increased oil recovery was experienced in both spontaneous and forced imbibition tests.
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

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

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

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

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 < 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

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

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

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

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

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.
Surveillance of Steam Assisted Gravity Drainage in In-Depth Extra-Heavy Oil Reservoir
Authors: Hongyuan Wang , Erpeng Guo
Published: March 2018

In 2008, We presented a paper "Application of Temperature Observation Wells during SAGD Operations in a Medium Deep Burial Extra Heavy Oil Reservoir" at the Petroleum Society's 59th Annual Technical Meeting. After 10 years SAGD technology is already widely adopted in exploiting extra heavy oil in China. This paper summarizes the experience on surveillance of SAGD project in the past years.

During SAGD process the adjustment of steam chamber in both vertical and horizontal direction and operation parameters should base on synthetic surveillance data. In the past, the surveillance approach is very limited and the results cannot be used as effective indicators. The successful application of reservoir based synthetic surveillance approach produced reliable data for management of SAGD project in Du 84 block Liaohe Oil field. The applied technical series include pressure/temperature observation wells, pressure/temperature monitoring in horizontal wells, time-lapse seismic monitoring, micro-gravity test etc. With the help of these monitoring data, the accurate and long term effective database was established.

The application of synthetic monitoring system provides the opportunity of accurate control of steam injection and production. The temperature and pressure observation well can monitor the vertical development of steam chamber, especially in gas-SAGD process. The observation well can detect the vertical sweep area of injected gas which can give effective approach in SAGD management. The temperature and pressure monitoring and tracer test can provide information for connection between injector and producer. 4-Dimensional seismic and 4-Dimensional micro gravity is a new approach of combination for petro-physical technology and petroleum development. 4D seismic not only can remap the geological body but also it can depict the steam chamber distribution in the reservoir. 4D micro gravity monitoring can accurately detect the front of steam chamber. With these data, the distribution of steam zone and residual oil is clear for future reservoir management.

This paper gives a verified approach of surveillance and the corresponding operation adjustment. And this can be guidance for design and application of new SAGD surveillance system.
The Last Chance? - Cyclic Steaming Pilot Project in Demjén West Field
Authors: Szelényi János
Published: March 2018

Demjén West is a shallow oil field with unsaturated paraffinic oil in Northern Hungary. Contrary to the long production history the recovery factor is only 13%. Already from the early years of the field number of experiments were completed to enhance production. Recently a new steam generating technology was tested. The objective was to collect information on the usability of the technology in the field and to test the reservoir behaviour for steaming.

First a technology test and demonstration day was organised for international companies in February 2016. After the successful testing an 8-cycle/8-week long pilot project was planned and completed in the summer of 2016. The cycles contained 2 days steam injection half a day soaking period and 5 days production. New heat resistant well equipment were fabricated for the project and a new well completion was applied. However the pilot was planned for an old existing well with the old SRP system what proved key issues for steam injection.

The paper introduces the steaming technology, the results and observations of this exciting cyclic steaming pilot project. A detailed monitoring system was planned and applied in the project. All the parameters of the new steam generating technology and the injection/production process were monitored. The nearby wells were also monitored and the produced fluids were sampled and tested in lab. The project faced to number of technical difficulties. However contrary to the technical problems and to the significantly less injected steam volume the production increased and the reservoir reacted well as it was expected. Observations proved that the injected steam and hot oxygen cleaned the pores of the near wellbore space from paraffin and heavy particles and improved the oil inflow to the well. The condition of the old well proved to be the weakest element of the process. The new steam generator could provide the planned volume of steam with the planned parameters (pressure and temperature). By solving the key technical problems cyclic steaming can be a viable technology to significantly improve the recovery from this old field.

The pilot project served valuable information for future operation. Cyclic steaming can be right solution to enhance recovery from Demjén West and from similar shallow heavy(er) oil fields. Successful and economically viable projects can be completed with new slim-hole wells and suitable lifting technology.
Thermal EOR Souring Prediction Tool - Technology for Cost Reduction; a Case Study from Thermal EOR Asset, Sultanate of Oman
Authors: Al-Aulaqi Talal , Dindoruk Birol , Zhang Etuan , Ward David , Al-Azri Nasser
Published: March 2018

Thermal EOR has been applied in different reservoirs in Oman to maximize the production from heavy oil prospects. PDO consider the highest HSE standard in their field operation to protect people and the integrity of the assets. In thermal EOR one of the highest HSE and risk integrity is the drastic increase of acid gas production mainly (H2S and CO2).

Historically, the quantification of the acid gas development in thermal EOR developments has been challenging, either leading to underestimation of the acid gas levels or overdesigning the material type with huge cost associated which impact the commerciality of the project especially at the current low oil price. Thus, improvement of the thermal souring prediction capabilities is required for the risk assessment and fit for purpose material selection rather than exotic option.

This work shows the results from an integrated subsurface and surface engineering collaboration to define the geochemical sources of souring in the thermal projects and to quantify the H2S/CO2 profile over the life cycle of the project. For the first time in PDO, a souring prediction workflow was developed and validated by coupling the reaction transport models with reservoir engineering dynamic models. The outcomes are used to define a safe operating envelope and move the operating mindset to be a proactive approach in managing the thermal souring risk.
Laboratory Study of a New EOR-Grade Scleroglucan
Authors: Fournier Remi , Tiehi Julien-Ey , Zaitoun Alain
Published: March 2018

Scleroglucan is a non-ionic exopolysaccharide produced by a specific fungi, called Sclerotium glucanicum. Due to its high viscosifying power and its good stability towards temperature and salinity, scleroglucan has been at the heart of several studies aiming at evaluating its potential for Enhanced Oil Recovery (EOR). As a biopolymer, scleroglucan is environmentally-friendly with no limitation of use in sensitive area such as offshore North Sea. Despite these promising features, the main pitfall of scleroglucan for EOR purposes has been its poor filterability, which is mainly explained by fermentation broth residues and polymer aggregates. This issue led researchers to use tedious filtration methods prior to experiments, which are not applicable in the field. To overcome this limitation, a new process was developed to obtain an EOR-grade scleroglucan which has been submitted to laboratory tests.

The first part of this paper presents bulk experiments with this new EOR-grade scleroglucan. Filtration tests enabled to assess the efficiency of the dissolution process and the homogeneity of the solution. The dissolution method was optimized to obtain a proper solubilization of the polymer. Rheological behavior was also investigated, showing the high viscosifying power of the product, much higher than conventional EOR products like hydrolyzed polyacrylamide.

In a second part, coreflood experiments were performed in high-permeability (Kw(Sw=1)=1.5 D) Bentheimer sandstone and medium-permeability (Kw(Sw=1-So,r)=120 mD) Estaillade limestone. The main highlight is that no particular pre-filtration process was needed prior to injection in the core. Indeed, very good injectivities were obtained in both rock types. Dynamic adsorption was low in Bentheimer sandstone, and in Estaillade limestone in the presence of a residual oil saturation.

This study qualifies this new EOR-grade scleroglucan for EOR applications. With a good injectivity, low adsorption levels, high resistance to temperature and salinity, and low environmental footprint, this polymer could advantageously replace hydrolyzed polyacrylamide, and its derivatives, in hightemperature and high-salinity reservoirs, and in sensitive offshore areas.
Case Study: Realization and Evaluation of Cyclic Steam Stimulation Pilot for Offshore Oilfield, China
Authors: Han Xiaodong , Liu Yigang , Liu Hao , Wang Qiuxia , Zou Jian , Zhang Hua , Wang Hongyu , Wu Xuanren
Published: March 2018

There is abundant heavy oil resource in Bohai oilfield, and only limited resource could be exploited with cold production technologies. Though cyclic steam stimulation is one of the most widely used and effective technology for onshore heavy oil exploitation around the world, this thermal method could not be directly applied for offshore oilfield for the limited space, bearing capacity and HSE requirement of the offshore platform.

For improving the offshore heavy oil production, feasibility study of the cyclic Steam stimulation for offshore oilfield was conducted and the relevant equipment was developed. A compact modular steam generator was specially developed for offshore steam injection process. The matching equipment including fuel tank, sea water desalinization and air compressor that could be easily resembled on the platform were developed. From engineering aspects, corrosion prevention, isolation tubing and wellhead were also provided for offshore operation. And the LD Oilfield whose underground oil viscosity is about 2336 mPa.s was selected for field pilot.

For field pilot, two horizontal wells has been implemented. 5 well times steam injection has been carried out since 2014 and the stimulation has entered the third rounds. Till now, the cumulative thermal oil production is about 60 thousand m3. When compared with the clod production, the peak oil production rate is about 5.3 times and cycle oil productivity is about 2 times that of the cold production, the valid time for each cycle is about 280 days. For analyzing the stimulation characteristics, the variation of temperature, pressure and saturation distribution in the near well region, and parameters analysis are conducted by reservoir simulation. The temperature profile test is also carried for analyzing the producing degree of the horizontal section of the thermal wells. The test result shows that the 300m horizontal section of the thermal well is evenly heated and the producing degree is relatively good.

In this paper, engineering design and field test of cyclic steam stimulation in Bohai Oilfield are introduced in detail. The result of field test shows that the steam generator are feasible to operate on offshore platform and the cyclic steam stimulation is practical to enhance offshore heavy oil production.
Minagish Middle Oolite Miscible Gas Injection Pilot: Inter-Well Tracer Campaign for the First Non-Thermal EOR Project in Kuwait
Authors: Al-Murayri M. T. , Al-Mayyan H. E. , Kamal D. S. , Ziyab D. K. , Chatterjee M. , Hewitt P.
Published: March 2018

A Miscible Hydrocarbon Gas injection pilot is being implemented by Kuwait Oil Company in the Minagish Middle Oolite (MN-MO) carbonate reservoir of West Kuwait. The water pre-flush phase of this pilot was initiated in March 2016 in preparation for subsequent miscible gas injection. An Inter-Well Tracer Test (IWTT) was performed during the water pre-flush phase to assess reservoir conformance and connectivity in a complex and highly laminated formation to support reservoir modeling activities.

Implementing an IWTT is an integral part of the overall surveillance/monitoring program to properly evaluate reservoir heterogeneities within and around the selected pilot area prior to miscible gas injection. Three different tracers were injected through the central injector into three geologically distinct, vertically stacked and inter-connected layers. Water samples were collected from three pilot producers on a regular basis for lab analysis to construct produced tracer curves. These tracer curves were then characterized analytically and compared with the original pilot performance forecasts that were generated using a reservoir sector model.

Tracer data showed reasonable breakthrough times and distinct peaks representing different flow paths for every injector-producer pair, involving one injector and three surrounding producers. Analytical interpretation of tracer data was useful to assess ultimate tracer production and swept volumes for each flow path. Based on the observed tracer breakthrough times during the water pre-flush phase, it can be inferred that limited preferential flow is expected during the subsequent miscible gas injection phase. The data from the above-mentioned IWTT and ensuing analytical characterization can be integrated with the on-going simulation activities to generate more reliable performance forecasts for miscible gas injection into the MN-MO carbonate reservoir.

This paper highlights how analytical interpretations can be derived for multiple flow paths in relation to water and miscible gas injection using IWTT data. The results from this study are important to enhance and fine-tune the reservoir simulation models that are being used in the meantime to generate reliable performance forecasts.
A Successful ASP Sweep Evaluation in a Field Pilot
Authors: Guntupalli S. , Kechichian J. , Al-Yaarubi A. , Al-Amri A. , Al-Amri M. , Al-Hinai G , Al-Shuaili K. , Svec Y. , Al Habsi Y.
Published: March 2018

A field in southern Oman has been identified for conducting an alkaline surfactant polymer (ASP) pilot project to enhance oil recovery. The potential benefit from ASP flooding had been estimated to be significant, based on coreflood investigations and single-well tests. The ASP pilot was initiated to derisk and support the financial investment decision for full-field implementation.

The vertical saturation estimates were obtained through state-of-the-art nuclear magnetic resonance (NMR) technology in the observation well, which was completed with fiber-reinforced plastic (FRP) casing and located midway between the injector and a producer of the pilot. Laboratory ASP flood experiments demonstrated that NMR response is insensitive to the chemistry of ASP/polymer solutions. The tool response provides salinity-independent inference for saturation profiling. These characteristics of NMR technology make it a suitable saturation monitoring tool for fields applying chemical enhanced oil recovery (EOR).

The pilot was executed with several phases, starting with pre-ASP waterflooding. This was followed by ASP slug injection, which, in turn, was followed by polymer chase and, ultimately, by chase water injection.

The base vertical saturation profile was established during the last stage of the pre-ASP waterflooding phase. The time-lapse vertical saturation profiles facilitated estimation of incremental desaturation during and after every stage of the injection phases. The dedicated multiphase flowmeters for each producer have also provided realtime oil production profiles to quantify the incremental oil production.

During the ASP pilot, NMR indicated the formation of an oil bank and desaturation due to ASP. This paper discusses the results of NMR during ASP pilot and the insights that NMR brings into understanding of subsurface performance and vertical sweep due to ASP.