Alkindi, Abdullah (Petroleum Development Oman) | Al-Azri, Nasser (Petroleum Development Oman) | Said, Dhiya (Petroleum Development Oman) | AlShuaili, Khalid (Petroleum Development Oman) | Te Riele, Paul (Shell Development Oman)
Primary and secondary recovery processes produce about one third of oil in place, leaving significant volumes behind. For low permeability and highly saline carbonate reservoirs, exploiting these resources is often challenging and unfeasible either technically and/or commercially.
In this paper we discuss the application of an emerging EOR technique that has shown promising results in the lab. Di-Methyl Ether (DME) enhanced waterflood (DEW) is a process in which DME is added to injection water, which upon injection into the reservoir, it preferentially partitions into the remaining oil. As a result, it swells the oil and reduces its viscosity which significantly improves oil mobility in the reservoir. Several core-flood experiments conducted in tight carbonate plugs have shown incremental recoveries of up-to 20% post waterflood. Additionally, the process provides significant acceleration to oil production, which would otherwise take several pore volume of water injection.
After successful PVT and core flood experiments, a field trial has been designed to de-risk this technology which if successful would add significant reserves. The pilot will be implemented in a tight carbonate reservoir that has been under waterflood. Some key uncertainties this pilot will address include solvent utilisation, oil incremental recovery, solvent back production and impact of geology on the process.
This paper discusses the key physical mechanisms of the process, pilot design and challenges of full field considerations. In addition, it also highlights key considerations when designing solvent-based EOR applications. The paper also highlights the need of lab work to mitigate operational issues prior to implementation. Calibrated numerical models were used to generate full field profiles, which show the need for a well optimised pattern design to make such processes feasible
This paper extends the subject of the ASP fullfield (re-) development and optimization discussed in the paper SPE-174680-MS to an ASP pilot in the same field using more detailed ASP simulation studies with a finer geological model. The study was targeted to investigate the roles of various static (e.g., geology), dynamic (e.g., fluid properties), ASP process (e.g., chemical adsorption) and numerical (e.g., grid size) parameters on the ASP performance prediction.
The paper focusses on three key subjects: firstly, understanding the ASP pilot performance under different realizations. Thereafter, we identify the key aspects of an ASP flood and break the problem statement into elements that are further investigated with the help of customized scenarios. We will share the results with regards to key sub-surface design elements for an ASP pilot, particularly highlighting what works and what does not, and how to improve the pilot response for a field with high degree of vertical heterogeneity.
A nationwide EOR screening was conducted on major oil fields in Kuwait with the aim to support KOC's long-term production strategy. Taking the many fields, and multitude of reservoirs into account, an efficient screening methodology was applied to high-grade potential EOR targets to focus on the most promising target formations.
This EOR screening methodology is an integrated approach of three steps. The first step applied parametric screening criteria of the various EOR technologies to the target formations of the study. The second step utilized analytical forecast models estimate tertiary recovery factors. The third and final step of this EOR screening methodology focused on generating a technical risk and opportunity profile for each filed, formation and applicable EOR technology.
This EOR screening methodology consisted of three steps. The first step applied parametric screening criteria of the various EOR technologies to the target formations of the study. The EOR processes in this parametric screening exercise included miscible gas EOR (such a CO2 and N2 as an example), chemical EOR technologies as well as thermal recovery technologies. During this first part of the EOR screening, the EOR technology yielding the highest incremental oil recovery in each formation was further studied while using analytical forecast models to link operational recovery drivers, such as throughput volumes and rates, to tertiary recovery factors. The third, and final step of this EOR screening methodology focused on generating a technical risk and opportunity profile for each field and formation under EOR screening while considering aspects such as EOR technology maturity, relative cost comparison and infrastructure constraints, to name a few. Integrating these three screening steps enabled to first, quickly focus on applicable EOR technologies for each target, second quantify a range of tertiary recovery factors and third estimate the risk profile. Combining these three outcomes enable to screen a portfolio of potential EOR opportunities quickly to find the most attractive target for further studies.
The novelty is the integrated EOR screening approach of combining parametric screening, analytical tertiary recovery forecasts and risk profiles to high-grade a portfolio of potential EOR targets for decision making.
Reichenbach-Klinke, Roland (BASF Construction Solutions GmbH) | Stavland, Arne (Harald Berland International Research Institute of Stavanger) | Strand, Daniel (Harald Berland International Research Institute of Stavanger) | Langlotz, Björn (BASF Construction Solutions GmbH) | Brodt, Gregor (BASF SE)
The oil recovery potential of acrylamide-based, associative thickening polymers has recently been evaluated in a coreflood study of our department. Associative polymers are anionic, water-soluble copolymers modified with varying degress of pendant hydrophobic groups. By intermolecular interactions of these hydrophobic moieties a fully reversible network of polymer coils can be formed.
The oil recovery efficiency of a series of copolymers based on acrylamide, 2-acrylamidopropane sulfonic acid (ATBS) in combination with a hydrophobic comonomer has been determined in linear coreflood experiments at a temperature of 60°C. Synthetic sea water was used as brine and Bentheimer sandstone as core material. The evaluated polymers differed in molecular weight and associative groups' content.
While anionic polyacrylamide (APAM) shows very similar resistance factors (RF) in coreflood experiments with and without oil, a significantly reduced RF in the presence of oil has been found for the associative polymers. The magnitude of this decrease in resistance factor was dependent on the specific type of associative polymer.
The effect can be ascribed to the weakend intermolecular interaction of the hydrophobic groups in the associative polymers in the presence of oil. Even though the RF value is reduced in the presence of oil, it still remains higher than that of regular APAM.
At low flow rates representing reservoir conditions a high resistance factor was observed and oil production was improved. This observation can be explained by an increase of the capillary number caused by the high RF of the polymer drive. A good correlation between oil production and capillary number was established.
Permeability reduction effects explained the high mobility reduction observed with the associative polymers, as the bulk viscosity data did not correlate with the in-situ flow properties of the polymers in porous media.
Al-Maamari, Rashid S. (Sultan Qaboos University) | Al-Hashmi, Abdulaziz (Sultan Qaboos University) | Al-Azri, Nasser (Petroleum Development Oman) | Al-Riyami, Omaira (Petroleum Development Oman) | Al-Mjeni, Rifaat (Petroleum Development Oman) | Dupuis, Guillaume (Poweltec) | Zaitoun, Alain (Poweltec)
A Polymer Flooding pilot trial has being implemented in a heavy oil field, in the South of Oman. A joint team composed of personnel from Sultan Qaboos University, Poweltec and Petroleum Development of Oman provided full laboratory support which included polymer products screening, and core-flooding experimental tests. The reservoir under investigation is a high-permeability sandstone with oil viscosity of around 500 mPa.s, brine salinity of around 5,000 ppm TDS and a subsurface temperature of 50°C. The reservoir characteristics are within the upper boundaries of known polymer flooding applications worldwide. This is further compounded by the presence of a strong bottom aquifer drive which requires the optimization of well placement.
Laboratory work consisted of both bulk and core-flood testing, in which different commercial hydrolyzed polyacrylamides were submitted to rheology, filtration and stability tests, from which one product was qualified. An intensive coreflood program was executed, consisting of rheology, adsorption and displacement experiments. Due to mild reservoir conditions (low salinity and temperature), the main focus was on filtration quality of the products. Following on from the filtration tests, coreflooding programs were implemented with very long sequence of polymer injection at a rate representative of polymer propagation in the reservoir.
Adsorption was found to be quite low (around 20 µg/g) for all the tested products. In-situ rheology was correlatable to the viscosity trends. The program of tests finally qualified a product with molecular weight of around 20 million Dalton. Above this level, long-term filtration becomes questionable with a slow but continuous ramp up of pressure noticeable after about 50 Pore Volumes.
The extreme heterogeneity of carbonate in the form of fracture corridors and super-permeability thief zones challenges the efficient sweep of oil in both secondary and tertiary recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any enhanced oil recovery (EOR) chemicals optimally contact the remaining oil with minimal throughput. Gel-based conformance control has been successfully applied on both sandstone and carbonate reservoirs. In-depth conformance control in high temperature reservoirs is still a challenge, due to severe gel syneresis and the associated significant reduction in gelation time.
In this work, a laboratory study was conducted to evaluate a polyacrylamide/chromium gel system for application in a high salinity and high temperature carbonate reservoir. Gel formulation was evaluated using different lab experiments including gelation time, gel strength, and long-term stability. Gelation time was determined by bottle tests and viscosity measurements. Long-term stability was evaluated both in bulk and in a core sample. For long-term gel stability in cores, a single-phase displacement experiment was performed to evaluate the ability of the selected gel system to effectively block high permeability zones. Multiphase displacement experiments were then conducted to evaluate the effectiveness of the gel treatment in oil recovery improvement. In these tests, the gel solution was injected into specially prepared heterogeneous carbonate core samples, in which high permeability channels were created by drilling centrally and mid-way through two core plugs that were brought together to constitute each composite core system.
Single-phase displacement experiments showed significant reduction in brine permeability after gel treatment. Even when the bulk gel volume was reduced by 50%, the original brine permeability is lowered by more than 80%. Multiphase displacement experiments demonstrated significant incremental recoveries post gel treatment. For example, a surfactant-polymer (SP) flood conducted after gel treatment resulted in an ultimate oil recovery of 83% original oil in core (OOIC), while without any gel treatment the SP flood attained an ultimate oil recovery of 67% OOIC. Results in this study demonstrate the potential of the studied gel system and its favorable impact on sweep efficiency for both water and chemical flooding applications in high temperature and high salinity carbonates.
Al-Rubkhi, A. A. (Sultan Qaboos University) | Karimi, M. (Sultan Qaboos University) | Hadji, M. (Department of Chemical Engineering, Faculty of Engineering, University Saad Dahlab, Blida) | Al-Maamari, R. S. (Sultan Qaboos University) | Aoudia, M. (Sultan Qaboos University)
The aim of this study is to develop and optimize a low tension water flood (LTWF) as an option for enhanced oil recovery in a tightcarbonate oilfield using a mixture of formation brines as injection water (total salinity: 165.9 g/L, Ca2+: 12.3 g/L, Mg2+: 2.0 g/L, and T = 70 °C.). In our approach, a combination of an anionic surfactant (alkyl ether sulfonate, C17EO7S(C17EO7) and a nonionic surfactant (alkyl ether, iC13EO10) were used to formulate clear and stable surfactant solutions at reservoir conditions.
Formulation and optimization of a LTWF at a very low total surfactant concentration (0.01 wt%) was achieved through surfactant/brine compatibility tests (target: clear and stable surfactant solution), surfactant solution/oil interfacial tensions (target: ~ 10-3 mNm-1), phase behavior (target: type II(-) oil-in-water microemulsion) and core flooding experiments.
Compatibility tests showed that the cloud point of the nonionic surfactant (0.01 wt%)is lower than the reservoir temperature (70 °C) whereas the clear point of the anionic surfactant is above the boiling point of water, suggesting that both surfactants cannot be used alone at reservoir conditions. On the other hand, clear and stable mixture of anionic/nonionic surfactants in the composition range fw = 0.1 – 0.8 (fw being the weight fraction of the nonionic surfactant) at 0.01 wt% total surfactant concentration were generated above 70 °C.
Clear, transparent and gel-free oil-in-water phase behavior with relatively high oil solubilization parameters (so ~ 125) were observed for surfactant mixture (0.01 wt%, fw = 0.1-0.8). These phase behaviors tests were validated by interfacial tension (IFT) measurements. Ultralow IFT (~ 10-3mN/m) was achieved at fw = 0.2. This optimum system was selected for core flooding experiments. Injecting surfactant (0.5PV) slug into a fully water flooded carbonate core sample resulted in additional oil recovery of 10 % of OOIP. This is a very significant result owing to the low surfactant concentration used (0.01 wt%). In another experiment, injecting a surfactant slug (0.5 PV) before water injection resulted in a total recovery of 75% of OOIP. In addition, Amott-Harvey test showed that wettability indices of the core plug samples used in the experiments changed within a narrow range (– 0.231 to + 0.164); suggesting an alteration of wettability from slightly oil-wet to weakly water-wet state.
Despite the increase of hydrocarbons exploitation from green fields in the last decades, the majority of the global production is still sustained by brown fields contribution. Rejuvenation of mature assets, as the one described in this work, plays a crucial role in current low oil price scenario, improving production with limited investments and risks.
Object of this work is an offshore oil field in the UK area in production since 1996. The field is developed by means of water injection for pressure maintenance and gas injection for disposal, with current water-cut higher than 90% and gas-breakthrough in wells close to the disposal area. After the acquisition of the operatorship in 2014, an asset rejuvenation project started, involving an integrated analysis of the field, based on the review of all available static and dynamic data. Combination of basic reservoir engineering tools and advanced modeling simulators was the key element of the performed analysis. This paper shows how an integrated workflow, combining skills from different professional families, allowed to find low cost opportunities with short time-to-market.
Production data analysis highlighted low efficiency of current water injection: majority of the injected volume is produced without displacing additional oil. Moreover, the new reservoir compositional model showed presence of by-passed oil in the crestal part of the field not displaced due to gravitational segregation effect.
Thanks to the better understanding of the field characteristics and fluids movement, different actions were planned in order to maximize oil recovery. In particular, a screening of possible IOR/EOR techniques showed immiscible WAG as the most promising one to recover un-swept attic oil. Several sensitivities were performed on water and gas injection rates, cycles duration and gas composition, in order to properly evaluate and maximize the expected additional recovery. Based on modeling results, two currently shut-in injectors were selected for a WAG pilot phase. The feasibility study highlighted that only minor plant changes were required, due to the availability of both water and gas injection facilities. This aspect drove the project economics into favorable evaluation. Moreover, moving gas injection from disposal to WAG mitigates well production problems in the disposing area, turning gas injection from an issue to opportunity extending field life.
This paper gives a detailed description of the rejuvenation project ongoing on an UK field which main outcome is the start-up of a WAG project. Advanced workflow, combining streamlines and conventional simulators, was used for waterflooding assessment and optimization. This integrated project was carried out with short time to market and minimal expenditure, showing how EOR processes can be an opportunity for field rejuvenation even in a low oil price environment.
MOL has more than 40-year experience in EOR applications in Hungary. As most of the fields approach to the end of their lifecycle more and more ideas were born to help these fields to survive.
Demjen is one of these old fields very close to its total depletion. During the 62 years production history number of EOR/IOR experiments were applied with various results. Contrary to the long production history the recovery factor of the field is only 15%. The main reasons of this poor recovery are the complex geological environment, the low pressure and temperature of the reservoirs and the oil quality.
In 2012 a new 3D geological model has been finished for Demjén field what tripled OIIP 3P resource. This increased potential has encouraged experts to review again the EOR/IOR project possibilities for the field.
Parallel to recently applied MEOR technology a cyclic steaming stimulation (CSS) pilot project is planned in Demjén West field for the next few years. The equipment intended to be used for steaming wells of the field is a revolutionary new technology that can easily move from well to well and it does not require high capex surface constructions. The well completion and some of the elements of the well structure is also designed especially for cyclic steaming of such old well.
The aim of this CSS pilot is to monitor the behavior of the reservoir as in-situ the oil has relatively high viscosity due to the low temperature and the high paraffin content also worsen oil flowing properties at that reservoir condition. Good results could give solid base to extend application of the technology to other areas and reservoirs of the field and for other EOR/IOR applications.
This article is copyrighted by SPE.
Al-Sinani, I. S. (Daleel Petroleum LLC) | Al-Jabri, S. H. (Daleel Petroleum LLC) | Al-Rawahy, N. A. (Daleel Petroleum LLC) | Al-Rawahy, I. (Ta'azeez Alneft) | Al-Hinai, K. (Ta'azeez Alneft) | Leksono, M. (Bandung Institute of Technology)
Most of the northern Oman fields have tight carbonate reservoirs. The field under study was initially produced under natural depletion with declining reservoir pressures through vertical and horizontal wells (1990-2002), then followed by two years water flood piloting and thereafter full field line drive water flood implementation through open hole horizontal wells.
After more than 10 years of water injection, water production increase is seen in most of the wells and water cut reached an average of 65-75% in the major producing blocks. Based on current data, the ultimate recovery factor of the current water flood development from these blocks is expected to be as high as 40-45%.
In sight of the continuous increase of water production from the field and taking into account that more than 50% of the field's oil initially in place will not be recovered by the current secondary production mechanism (water flood), the block operator initiated research work on the tertiary production mechanism to maximize the oil recovery from the field. Extensive laboratory and field testing works were performed over the past five years to select the suitable and optimum IOR/EOR technique to be implemented in this tight carbonate reservoir. The process started with screening of different EOR methods and was followed by laboratory fluid behavior testing and core flooding experiments for the selected method. Out of all EOR methods, chemical EOR was screened as the most convenient and applicable method to be implemented due to the nature of both reservoir and fluid. This paper summarizes the working process which was followed to eventually select the convenient chemical starting from screening process, then laboratory work, followed by single well field testing and eventually extended injection field testing. High level results will be presented for the first three milestones and more elaborations on the extended injection field testing will be presented. Results for both field trials; the huff and puff and the extended injection are encouraging with incremental oil gains exceeding the expectation from these trials.
The extended chemical injection field trial was executed in ~ 40 acre, horizontal line drive pattern utilizing two horizontal injectors and four horizontal producers with two vertical pressure observation wells. The evaluation of injection results was based on actual daily production and injection data as well as reservoir log and core data collected before chemical injection. Comparing to water flood, initial recovery factor evaluation indicate possible improvement of up to 18% (per pore volume injected) in unit A which has more mature water flood where water cut exceeding 80% but less oil volume. Recovery improvement in unit B, a less mature water flood reservoir unit, was not remarkable. Post job analysis and review claims this due to the relatively immature water injection and thus lower water cut in this reservoir unit. Unit B is also three times thicker than unit A, which meant it received a lower chemical volume, which might have resulted in a lower recovery performance.
With limited field trials of surfactant injection in tight carbonate reservoirs in Middle East, this case study will help to enrich the literature with actual field data of continues surfactant injection in tight carbonate field.