scholarly journals Insights into Oil Recovery Mechanism by Nothing-Alternating-Polymer NAP Concept

2021 ◽  
Author(s):  
Muatasam Battashi ◽  
Rouhi Farajzadeh ◽  
Aisha Bimani ◽  
Mohammed Abri ◽  
Rifaat Mjeni ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Sultanate Of Oman ◽  
Water Contact ◽  
Utilization Factor ◽  
Polymer Injection ◽  
Recovery Mechanism ◽  
Cyclic Polymer ◽  
Negative Effect ◽  
Oil Water ◽  
Water Cut

Abstract This paper discusses the application of polymer injection in a heavy oil reservoir in the South of the Sultanate of Oman containing oil with a viscosity of 300-800cP underlain by a strong bottom-up aquifer. Due to unfavorable mobility ratio between aquifer water and oil and the development of the sharp cones significant amount of oil remains unswept. To overcome these issues, a polymer injection pilot started in 2013 with three horizontal injectors, located a few meters above the oil/water contact. Initially a polymer solution with a viscosity of 100 cP was continuously injected at high injection rates. However, it was challenging to sustain the injectivity mainly due to surface facilities, water, and polymer quality issues. This resulted in frequent shutdowns of the injectors. Interestingly, the water cut reversal and oil gain continued during the shut-in periods. This observation has led to the development of a new cyclic polymer injection strategy, in which the injection of polymer is alternated with shut-ins. The strategy is referred to as Nothing-Alternating-Polymer (NAP). This paper discusses the oil recovery mechanism from the NAP strategy. A 3D model was constructed to match the actual pilot results and capture the observed behavior. The injected polymer squeezes the cones and partly restores the barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative affect of the cones. It was found that during polymer injection, the oil is recovered by conventional mobility and sweep enhancement mechanisms ahead of the polymer front. Additionally, during this stage the injected polymer creates a barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative effect of the cones or water channels (blanketing mechanism). Moreover, injection of polymer pushes the oil to the depleted water cones, which is then is produced by the water coming from the aquifer during shut-in period (recharge mechanism). During the shut-in or NAP period, the aquifer water also pushes the existing polymer bank and hence leads to extra oil production. The NAP strategy reduces polymer loss into aquifer and improves the polymer utilization factor expressed in kg-polymer/bbl of oil, resulting in a favorable economic outcome.

Real-Time EM Look-Ahead Resistivity for Mapping of Oil/Water Contact While Drilling at Low Deviated Well, New Perspective for Mature Oil Fields Development: A Case Study Of Umm Gudair Field, Kuwait

2021 ◽  
Author(s):  
Nasser Faisal Al-Khalifa ◽  
Mohammed Farouk Hassan ◽  
Deepak Joshi ◽  
Asheshwar Tiwary ◽  
Ihsan Taufik Pasaribu ◽  
...  
Keyword(s):  
Water Saturation ◽  
High Water ◽  
Carbonate Reservoir ◽  
Water Contact ◽  
Saturation Zone ◽  
Look Ahead ◽  
Production History ◽  
Oil Water ◽  
High Water Cut ◽  
Water Cut

Abstract The Umm Gudair (UG) Field is a carbonate reservoir of West Kuwait with more than 57 years of production history. The average water cut of the field reached closed to 60 percent due to a long history of production and regulating drawdown in a different part of the field, consequentially undulating the current oil/water contact (COWC). As a result, there is high uncertainty of the current oil/water contact (COWC) that impacts the drilling strategy in the field. The typical approach used to develop the field in the lower part of carbonate is to drill deviated wells to original oil/water contact (OOWC) to know the saturation profile and later cement back up to above the high-water saturation zone and then perforate with standoff. This method has not shown encouraging results, and a high water cut presence remains. An innovative solution is required with a technology that can give a proactive approach while drilling to indicate approaching current oil/water contact and geo-stop drilling to give optimal standoff between the bit and the detected water contact (COWC). Recent development of electromagnetic (EM) look-ahead resistivity technology was considered and first implemented in the Umm Gudair (UG) Field. It is an electromagnetic-based signal that can detect the resistivity features ahead of the bit while drilling and enables proactive decisions to reduce drilling and geological or reservoir risks related to the well placement challenges.

Advancement Towards the Full-Field Implementation of Marmul Alkaline-Surfactant-Polymer in the Sultanate of Oman

2021 ◽  
Author(s):  
Dawood Al Mahrouqi ◽  
Hanaa Sulaimani ◽  
Rouhi Farajzadeh ◽  
Yi Svec ◽  
Samya Farsi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Phase 1 ◽  
Recovery Efficiency ◽  
Sultanate Of Oman ◽  
Water Separation ◽  
Full Field ◽  
Oil Water Separation ◽  
Oil Water ◽  
New Formulation ◽  
Alkaline Surfactant Polymer

Abstract In 2015-2016, the Alkaline-Surfactant-Polymer (ASP) flood Pilot in Marmul was successfully completed with ∼30% incremental oil recovery and no significant operational issues. In parallel to the ASP pilot, several laboratory studies were executed to identify an alternative and cost-efficient ASP formulation with simpler logistics. The studies resulted in a new formulation based on mono-ethanolamine (MEA) as alkali and a blend of commercially available and cheaper surfactants. To expediate the phased full field development, Phase-1 project was started in 2019 with the following main objectives are confirm high oil recovery efficiency of the new ASP formulation and ensure the scalability and further commercial maturation of ASP technology; de-risk the injectivity of new formulation; and de-risk oil-water separation in the presence of produced ASP chemicals. The Phase 1 project was executed in the same well pattern as the Pilot, but at a different reservoir unit that is more heterogeneous and has a smaller pore volume (PV) than those of the Pilot. This set-up allowed comparing the performance of ASP formulations and taking advantage of the existing surface facilities, thus reducing the project cost. The project was successfully finished in December 2020, and the following major conclusions were made: (1) with the estimated incremental recovery of around 15-18% and one of the producers exhibiting water cut reversal of more than 30%, the new ASP formulation is efficient and will be used in the follow-up phased commercial ASP projects; (2) the injectivity was sustained throughout the entire operations within the target rate and below the fracture pressure; (3) produced oil quality met the export requirements and a significant amount of oil-water separation data was collected. With confirmed high oil recovery efficiency for the cheaper and more convenient ASP formulation, the success of ASP flooding in the Phase-1 project paves the way for the subsequent commercial-scale ASP projects in the Sultanate of Oman.

Barrow Island enhanced oil recovery polymer pilot—part two: progress and way forward

2011 ◽  
Vol 51 (2) ◽  
pp. 672
Author(s):  
Daniel León ◽  
John Scott ◽  
Steven Saul ◽  
Lina Hartanto ◽  
Shannon Gardner ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Injection Pressure ◽  
Fracture Network ◽  
Oil Field ◽  
High Porosity ◽  
Polymer Injection ◽  
Fine Grained ◽  
Successful Design ◽  
Fit For Purpose ◽  
Water Cut

After successful design and implementation phases that included both subsurface and facilities components, an EOR polymer injection pilot has been operational for two years in Australia's largest onshore oil field at Barrow Island (816 MMstb OOIP). The pilot's main objective was to identify a suitable EOR technology for the complex, highly heterogeneous, very fine-grained, bioturbated argillaceous sandstone—high in glauconite, high porosity (∼23 %), low permeability (∼5 mD, with 50+ mD streaks)—reservoir that will ultimately increase the recovery of commercial resources past the estimated ultimate recovery factor with waterflooding (∼42 %). This was achieved using the in-depth flow diversion (IFD) methodology to access new unswept oil zones—both vertically and horizontally—by inducing growth in the fracture network. During the pilot operating phase, the main focus has been on surveillance and monitoring activities to assess the effectiveness of the process, including: injection pressure at the wellheads—indicating any increase in resistance to flow; pressure fall off tests at the injectors—to determine fracture growth, if any sampling and lab analysis at the producers—to identify polymer breakthrough; frequent production tests—quantifying reduction in water cut and oil production uplift; and, pressure build up surveys at the producers. These activities provided input data to the fit for purpose simulation model built in Reveal incorporating fractures and polymer as a fourth phase. With more than 96 % compliance to the surveillance plan, this paper will present the present findings and evaluation of the results, which may lead to the continuation of the pilot in other patterns of the reservoir and, possibly, to further expansion in the field.

The Blane Field, Block 30/3a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 382-389 ◽  
Author(s):  
K. Robertson ◽  
R. Heath ◽  
R. Macdonald
Keyword(s):  
North Sea ◽  
Oil Production ◽  
Water Contact ◽  
Stock Tank ◽  
Light Oil ◽  
Oil Water ◽  
Water Cut ◽  
The Uk ◽  
Central North Sea ◽  
Structural Closure

AbstractThe Blane Field is located in the central North Sea in Block 30/3a (Licence P.111), approximately 130 km SE of the Forties Field, in a water depth of 75 m (246 ft). It straddles the UK/Norway median line with 82% of the field in the UK and 18% in Norway. Blane produces undersaturated oil from the Upper Forties Sandstone Member of the Sele Formation and contains good quality light oil within a four-way structural closure; it has a hydrodynamically tilted original oil–water contact. The field stock-tank oil initially in place estimate is 93 MMbbl with an expected ultimate recovery of 33 MMbbl. Blane first oil was achieved in September 2007. The field has been developed by two horizontal producers located on the central crest of the field supported by a water injector drilled on the NW flank. Oil production peaked at c. 17 000 bopd in 2007 and the field is currently in decline. By the end of 2018 production was c. 3000 bopd with 55% water-cut. Cumulative oil production to the end of 2018 was 26.6 MMbbl.

scholarly journals Chemical enhanced oil recovery and the dilemma of more and cleaner energy

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Rouhi Farajzadeh ◽  
Siavash Kahrobaei ◽  
Ali Akbari Eftekhari ◽  
Rifaat A. Mjeni ◽  
Diederik Boersma ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Energy Demand ◽  
Produced Water ◽  
Transition Period ◽  
Water Injection ◽  
Energy Transition ◽  
Polymer Injection ◽  
Water Fraction ◽  
Water Cut

AbstractA method based on the concept of exergy-return on exergy-investment is developed to determine the energy efficiency and CO2 intensity of polymer and surfactant enhanced oil recovery techniques. Exergy is the useful work obtained from a system at a given thermodynamics state. The main exergy investment in oil recovery by water injection is related to the circulation of water required to produce oil. At water cuts (water fraction in the total liquid produced) greater than 90%, more than 70% of the total invested energy is spent on injection and lift pumps, resulting in large CO2 intensity for the produced oil. It is shown that injection of polymer with or without surfactant can considerably reduce CO2 intensity of the mature waterflood projects by decreasing the volume of produced water and the exergy investment associated with its circulation. In the field examples considered in this paper, a barrel of oil produced by injection of polymer has 2–5 times less CO2 intensity compared to the baseline waterflood oil. Due to large manufacturing exergy of the synthetic polymers and surfactants, in some cases, the unit exergy investment for production of oil could be larger than that of the waterflooding. It is asserted that polymer injection into reservoirs with large water cut can be a solution for two major challenges of the energy transition period: (1) meet the global energy demand via an increase in oil recovery and (2) reduce the CO2 intensity of oil production (more and cleaner energy).

Adjustment of Hydrophilic-Lipophilic Balance of Hexamethyldisilazane-Modified Nanosilica for Enhanced Oil Recovery

NANO ◽  
2019 ◽  
Vol 14 (02) ◽  
pp. 1950020 ◽  
Author(s):  
Xiaohe Tao ◽  
Sai Guo ◽  
Peisong Liu ◽  
Xiaohong Li ◽  
Zhijun Zhang
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Contact Angles ◽  
Water Flooding ◽  
Water Contact ◽  
Surface Hydroxyl ◽  
Hydrophilic Lipophilic Balance ◽  
Transfer Behavior ◽  
Oil Water

Different dosages of hexamethyldisilazane (denoted as HMDS), a silane coupling agent, were adopted to modify nanosilica (denoted as NS) to afford a series of HMDS-NS nanoparticles with different hydrophilic-lipophilic balance governed by the amount of surface hydroxyl. The amounts of the hydrophilic hydroxyl of the as-prepared HMDS-NS nanoparticles and their water contact angles were measured, and their dispersing behavior in water and oil was examined in relation to their transfer behavior therein. Moreover, the effects of the as-prepared HMDS-NS nanofluids on the oil–water interfacial tension as well as the oil recovery were investigated based on interfacial tension measurements and simulated rock core flooding tests. Findings indicate that the hydrophilic-lipophilic balance of HMDS-NS nanoparticles highly depends on the amount of the surface hydroxyl, and the surface hydroxyl amount can be well adjusted by properly selecting the dosage of HMDS modifier. Besides, the transfer behavior of HMDS-NS nanoparticles in oil and water is closely related to their hydrophilic-lipophilic balance, and they can greatly reduce the oil–water interfacial tension and increase the oil recovery by 7.7–11.1% as compared with conventional water flooding. This is because the surface grafting of the hydrophobic segments of HMDS leads to a significant increase in the hydrophobicity of nanosilica, thereby changing the wettability of oil on the sand surface and favoring the stripping of oil droplets. Particularly, the HMDS-NS nanofluid obtained with 2[Formula: see text]wt.% of HMDS modifier has a water contact angle of 83.6∘ and can dramatically reduce the oil–water interfacial tension from 20.22[Formula: see text]mN/m to 0.28[Formula: see text]mN/m, showing desired hydrophilic-lipophilic balance and potential for enhanced oil recovery associated with chemical flooding.

IMPROVING THE EFFICIENCY OF OPERATING AN OIL WELL WITH BOTTOM WATER

2021 ◽  
Author(s):  
Ильяс Азаматович Ишбулатов
Keyword(s):  
Oil Recovery ◽  
Bottom Water ◽  
Recovery Factor ◽  
Oil Well ◽  
Well Production ◽  
Oil Water ◽  
Water Cut

При разработке водонефтяных зон наблюдается образование конусов подошвенной воды, что ведет к увеличению обводненности скважинной продукции и снижению коэффициента извлечения нефти (КИН). В качестве одного из методов борьбы с данным явлением возможно применение технологии, описанной в патенте RU 2 730 163 C1. В данной статье представлены результаты моделирования данной технологии в гидроди-намическом симуляторе. During the development of oil-water zones, the formation of bottom water cones is observed, which leads to an increase in the water cut of the well production and a decrease in the oil recovery factor. As one of the methods to combat this phenomenon, it is possible to use the technology described in patent RU 2 730 163 C1. This article presents the results of modeling this technology in a hydrodynamic simulator.

scholarly journals Optimization of reserve production from water oil zones of D3ps horizon of Shkapovsky oil field by means of horizontal wells

Georesursy ◽  
2019 ◽  
Vol 21 (3) ◽  
pp. 55-61 ◽  
Author(s):  
Rustem F. Yakupov ◽  
Vyacheslav Sh. Mukhametshin ◽  
Ilgizar N. Khakimzyanov ◽  
Viktor E. Trofimov
Keyword(s):  
Oil Field ◽  
Residual Oil ◽  
Hydrodynamic Models ◽  
Water Contact ◽  
Oil Reserves ◽  
Physical Conditions ◽  
Production Values ◽  
Cone Formation ◽  
Oil Water ◽  
Water Cut

An analysis was made of the development of sections of the D3ps formation of the Devonian terrigenous sequence of the Shkapovsky field, with a share of contact zones of more than 78%, which showed that the exploitation of deposits by vertical and deviated wells is unprofitable. Studies show that the development of reserves at the facility occurs along highly permeable interlayers located in the plantar. The construction of sectoral geological and hydrodynamic models showed a detailed distribution of residual oil reserves by area and section in areas with low production values. When analyzing the parameters of the operation of wells with horizontal completion, it was found that the selection of mobile oil reserves localized in a volume limited by the plane of the initial oil-water contact and the surface formed by the rise of the oil-water contact when pulling the water cone to the wells with horizontal completion is comparable with the period of reaching a water cut of 95%. The volumetric method was used to calculate the moving oil reserves in the area of ​​water cone formation. It is recommended to drill wells with horizontal completion as an effective method of additional production of residual oil reserves in fields with similar geological and physical conditions.

Immiscible CO2-Assisted Gravity Drainage Process for Enhancing Oil Recovery in Bottom Water Drive reservoir

2020 ◽  
Vol 27 (2) ◽  
pp. 60-66
Author(s):  
Dahlia A. Al-Obaidi ◽  
Mohammed S. Al-Jawad
Keyword(s):  
Oil Recovery ◽  
Bottom Water ◽  
Physical Models ◽  
Recovery Factor ◽  
Gravity Drainage ◽  
Ambient Conditions ◽  
Water Contact ◽  
3D Simulation Model ◽  
Water Cut ◽  
Enhance Oil Recovery

The CO2-Assisted Gravity Drainage process (GAGD) has been introduced to become one of the mostinfluential process to enhance oil recovery (EOR) methods in both secondary and tertiary recovery through immiscibleand miscible mode. Its advantages came from the ability of this process to provide gravity-stable oil displacement forenhancing oil recovery. Vertical injectors for CO2 gas have been placed at the crest of the pay zone to form a gas capwhich drain the oil towards the horizontal producing oil wells located above the oil-water-contact. The advantage ofhorizontal well is to provide big drainage area and small pressure drawdown due to the long penetration. Manysimulation and physical models of CO2-AGD process have been implemented at reservoir and ambient conditions tostudy the effect of this method to improve oil recovery and to examine the most parameters that control the CO2-AGDprocess. The CO2-AGD process has been developed and tested to increase oil recovery in reservoirs with bottom waterdrive and strong water coning tendencies. In this study, a scaled prototype 3D simulation model with bottom waterdrive was used for CO2-assisted gravity drainage. The CO2-AGD process performance was studied. Also the effects ofbottom water drive on the performance of immiscible CO2 assisted gravity drainage (enhanced oil recovery and watercut) was investigated. Four different statements scenarios through CO2-AGD process were implemented. Resultsrevealed that: ultimate oil recovery factor increases considerably when implemented CO2-AGD process (from 13.5%to 84.3%). Recovery factor rises with increasing the activity of bottom water drive (from 77.5% to 84.3%). Also,GAGD process provides better reservoir pressure maintenance to keep water cut near 0% limit until gas flood frontreaches the production well if the aquifer is active, and stays near 0% limit at all prediction period for limited waterdrive.

Sign in / Sign up

Export Citation Format

Share Document