Conformance Control in Horizontal Wells for Steam and Polymer Flooding Project in the Sultanate of Oman

2010 ◽  
Author(s):  
Gary Howell Lanier ◽  
Apollo Leonard Kok ◽  
Andrea Young-Mclaren ◽  
Murshid Mohammed Al-Riyami ◽  
Muneer Ahmed Ambusaidi ◽  
...  
Keyword(s):  
Horizontal Wells ◽  
Polymer Flooding ◽  
Sultanate Of Oman ◽  
Conformance Control

Revision of Pressure Transient Analysis in Mature Condensate-Rich Tight Gas Fields in Sultanate of Oman

2022 ◽  
Author(s):  
Ahmed Elsayed Hegazy ◽  
Mohammed Rashdi
Keyword(s):  
Transient Analysis ◽  
Horizontal Wells ◽  
Development Planning ◽  
Reservoir Modeling ◽  
Sultanate Of Oman ◽  
Pressure Transient Analysis ◽  
Pressure Transient ◽  
Full Field ◽  
Gas Fields ◽  
Half Length

Abstract Pressure transient analysis (PTA) has been used as one of the important reservoir surveillance tools for tight condensate-rich gas fields in Sultanate of Oman. The main objectives of PTA in those fields were to define the dynamic permeability of such tight formations, to define actual total Skin factors for such heavily fractured wells, and to assess impairment due to condensate banking around wellbores. After long production, more objectives became also necessary like assessing impairment due to poor clean-up of fractures placed in depleted layers, assessing newly proposed Massive fracturing strategy, assessing well-design and fracture strategies of newly drilled Horizontal wells, targeting the un-depleted tight layers, and impairment due to halite scaling. Therefore, the main objective of this paper is to address all the above complications to improve well and reservoir modeling for better development planning. In order to realize most of the above objectives, about 21 PTA acquisitions have been done in one of the mature gas fields in Oman, developed by more than 200 fractured wells, and on production for 25 years. In this study, an extensive PTA revision was done to address main issues of this field. Most of the actual fracture dynamic parameters (i.e. frac half-length, frac width, frac conductivity, etc.) have been estimated and compared with designed parameters. In addition, overall wells fracturing responses have been defined, categorized into strong and weak frac performances, proposing suitable interpretation and modeling workflow for each case. In this study, more reasonable permeability values have been estimated for individual layers, improving the dynamic modeling significantly. In addition, it is found that late hook-up of fractured wells leads to very poor fractures clean out in pressure-depleted layers, causing the weak frac performance. In addition, the actual frac parameters (i.e. frac-half-length) found to be much lower than designed/expected before implementation. This helped to improve well and fracturing design and implementation for next vertical and horizontal wells, improving their performances. All the observed PTA responses (fracturing, condensate-banking, Halite-scaling, wells interference) have been matched and proved using sophisticated single and sector numerical simulation models, which have been incorporated into full-field models, causing significant improvements in field production forecasts and field development planning (FDP).

Improving Proppant Placement Success in Horizontal Wells in Layered Reservoirs in the Sultanate of Oman

2021 ◽  
Author(s):  
Andrew Boucher ◽  
Josef Shaoul ◽  
Inna Tkachuk ◽  
Mohammed Rashdi ◽  
Khalfan Bahri ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Complex Geometry ◽  
Horizontal Wells ◽  
Vertical Position ◽  
Sultanate Of Oman ◽  
Vertical Wells ◽  
Multiple Fractures ◽  
Initiation Point ◽  
Interval Selection ◽  
Geological Units

Abstract A gas condensate field in the Sultanate of Oman has been developed since 1999 with vertical wells, with multiple fractures targeting different geological units. There were always issues with premature screenouts, especially when 16/30 or 12/20 proppant were used. The problems placing proppant were mainly in the upper two units, which have the lowest permeability and the most heterogeneous lithology, with alternating sand and shaly layers between the thick competent heterolith layers. Since 2015, a horizontal well pilot has been under way to determine if horizontal wells could be used for infill drilling, focusing on the least depleted units at the top of the reservoir. The horizontal wells have been plagued with problems of high fracturing pressures, low injectivity and premature screenouts. This paper describes a comprehensive analysis performed to understand the reasons for these difficulties and to determine how to improve the perforation interval selection criteria and treatment approach to minimize these problems in future horizontal wells. The method for improving the success rate of propped fracturing was based on analyzing all treatments performed in the first seven horizontal wells, and categorizing their proppant placement behavior into one of three categories (easy, difficult, impossible) based on injectivity, net pressure trend, proppant pumped and screenout occurrence. The stages in all three categories were then compared with relevant parameters, until a relationship was found that could explain both the successful and unsuccessful treatments. Treatments from offset vertical wells performed in the same geological units were re-analyzed, and used to better understand the behavior seen in the horizontal wells. The first observation was that proppant placement challenges and associated fracturing behavior were also seen in vertical wells in the two uppermost units, although to a much lesser extent. A strong correlation was found in the horizontal well fractures between the problems and the location of the perforated interval vertically within this heterogeneous reservoir. In order to place proppant successfully, it was necessary to initiate the fracture in a clean sand layer with sufficient vertical distance (TVT) to the heterolith (barrier) layers above and below the initiation point. The thickness of the heterolith layers was also important. Without sufficient "room" to grow vertically from where it initiates, the fracture appears to generate complex geometry, including horizontal fracture components that result in high fracturing pressures, large tortuosity friction, limited height growth and even poroelastic stress increase. This study has resulted in a better understanding of mechanisms that can make hydraulic fracturing more difficult in a horizontal well than a vertical well in a laminated heterogeneous low permeability reservoir. The guidelines given on how to select perforated intervals based on vertical position in the reservoir, rather than their position along the horizontal well, is a different approach than what is commonly used for horizontal well perforation interval selection.

Fieldwide Application of Autonomous Inflow Control Valve in Increasing the Field Recovery in One of the Matured Fields in the Sultanate of Oman: Case Study

2021 ◽  
Author(s):  
Salim Buwauqi ◽  
Ali Al Jumah ◽  
Abdulhameed Shabini ◽  
Ameera Harrasi ◽  
Tejas Kalyani ◽  
...  
Keyword(s):  
Control Valve ◽  
Oil Production ◽  
Horizontal Wells ◽  
High Water ◽  
Lessons Learned ◽  
Water Production ◽  
Sultanate Of Oman ◽  
Well Performance ◽  
Reservoir Conditions ◽  
Water Cut

Abstract One of the largest operators in the Sultanate of Oman discovered a clastic reservoir field in 1980 and put it on production in 1985. The field produces viscous oil, ranging from 200 - 2000+ cP at reservoir conditions. Over 75% of the wells drilled are horizontal wells and the field is one of the largest producers in the Sultanate of Oman. The field challenges include strong aquifer, high permeability zones/faults and large fluid mobility contrast have resulted that most of the wells started with very high-water cuts. The current field water cut is over 94%. This paper details operator's meticulous journey in qualification, field trials followed by field-wide implementation and performance evaluation of Autonomous Inflow Control Valve (AICV) technology in reducing water production and increasing oil production significantly. AICV can precisely identify the fluid flowing through it and shutting-off the high water or gas saturated zones autonomously while stimulating oil production from healthy oil-saturated zones. Like other AICDs (Autonomous Inflow Control Device) AICV can differentiate the fluid flowing through it via fluid properties such as viscosity and density at reservoir conditions. However, AICVs performance is superior due to its advanced design based on Hagen-Poiseuille and Bernoulli's principles. This paper describes an AICV completion design workflow involving a multi-disciplinary team as well as some of the field evaluation criteria to evaluate AICV well performance in the existing and in the new wells. The operator has completed several dozens of production wells with AICV technology in the field since 2018-19. Based on the field performance review, it has shown the benefit of accelerating oil production as well as reduction of unwanted water which not only reduces the OPEX of these wells but at the same time enormous positive impact on the environment. Many AICV wells started with just 25-40 % water cut and are still producing with low water cut and higher oil production. Based on the initial field-wide assessment, it is also envisaged that AICV wells will assist in achieving higher field recovery. Also, AICV helped in mitigating the facility constraints of handling produced water which will allow the operator continued to drill in-fill horizontal wells. Finally, the paper also discusses in detail the long-term performance results of some of the wells and their impact on cumulative field recovery as well as lessons learned to further optimise the well performance. The technology has a profound impact on improved sweep efficiency and as well plays an instrumental role in reducing the carbon footprint by reducing the significant water production at the surface. It is concluded that AICV technology has extended the field and wells life and proved to be the most cost-effective field-proven technology for the water shut-off application.

Sizing Gelant Treatment for Conformance Control in Hydraulically-Fractured Horizontal Wells

2020 ◽  
Author(s):  
Bin Liang ◽  
Hanqiao Jiang ◽  
Junjian Li ◽  
Min Li ◽  
Yuzheng Lan ◽  
...  
Keyword(s):  
Horizontal Wells ◽  
Conformance Control ◽  
Fractured Horizontal Wells

scholarly journals Prediction of Conformance Control Performance for Cyclic-Steam-Stimulated Horizontal Well Using the XGBoost: A Case Study in the Chunfeng Heavy Oil Reservoir

Energies ◽  
2021 ◽  
Vol 14 (23) ◽  
pp. 8161
Author(s):  
Zehao Xie ◽  
Qihong Feng ◽  
Jiyuan Zhang ◽  
Xiaoxuan Shao ◽  
Xianmin Zhang ◽  
...  
Keyword(s):  
Numerical Simulations ◽  
Heavy Oil ◽  
Oil Production ◽  
Horizontal Wells ◽  
Training Data ◽  
Gradient Boosting ◽  
Oil Reservoir ◽  
Conformance Control ◽  
Extreme Gradient Boosting ◽  
Heavy Oil Reservoir

Conformance control is an effective method to enhance heavy oil recovery for cyclic-steam-stimulated horizontal wells. The numerical simulation technique is frequently used prior to field applications to evaluate the incremental oil production with conformance control in order to ensure cost-efficiency. However, conventional numerical simulations require the use of specific thermal numerical simulators that are usually expensive and computationally inefficient. This paper proposed the use of the extreme gradient boosting (XGBoost) trees to estimate the incremental oil production of conformance control with N2-foam and gel for cyclic-steam-stimulated horizontal wells. A database consisting of 1000 data points was constructed using numerical simulations based on the geological and fluid properties of the heavy oil reservoir in the Chunfeng Oilfield, which was then used for training and validating the XGBoost model. Results show that the XGBoost model is capable of estimating the incremental oil production with relatively high accuracy. The mean absolute errors (MAEs), mean relative errors (MRE) and correlation coefficients are 12.37/80.89 t, 0.09%/0.059% and 0.99/0.98 for the training/validation sets, respectively. The validity of the prediction model was further confirmed by comparison with numerical simulations for six real production wells in the Chunfeng Oilfield. The permutation indices (PI) based on the XGBoost model indicate that net to gross ratio (NTG) and the cumulative injection of the plugging agent exerts the most significant effects on the enhanced oil production. The proposed method can be easily transferred to other heavy oil reservoirs, provided efficient training data are available.

Taking A Nap: Passive EOR Implementation for Resilient Management of Cost and OPEX for A Polymer Flood Project with Horizontal Wells in South Sultanate of Oman

2019 ◽  
Author(s):  
Ali Al-Jumah ◽  
Faisal Saadi ◽  
Khalfan Harthy ◽  
Sakeena Lawati ◽  
Saja Khaburi ◽  
...  
Keyword(s):  
Horizontal Wells ◽  
Sultanate Of Oman ◽  
Polymer Flood

scholarly journals Hybrid Chemical Enhanced Oil Recovery Techniques: A Simulation Study

Symmetry ◽  
2020 ◽  
Vol 12 (7) ◽  
pp. 1086 ◽  
Author(s):  
Haiyan Zhou ◽  
Afshin Davarpanah
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Field Data ◽  
Polymer Flooding ◽  
Oil Field ◽  
Recovery Factor ◽  
Surfactant Flooding ◽  
Conformance Control ◽  
Recovery Techniques ◽  
Polymer Surfactant

Simultaneous utilization of surfactant and preformed particle gel (henceforth; PPG) flooding on the oil recovery enhancement has been widely investigated as a preferable enhanced oil recovery technique after the polymer flooding. In this paper, a numerical model is developed to simulate the profound impact of hybrid chemical enhanced oil recovery methods (PPG/polymer/surfactant) in sandstone reservoirs. Moreover, the gel particle conformance control is considered in the developed model after polymer flooding performances on the oil recovery enhancement. To validate the developed model, two sets of experimental field data from Daqing oil field (PPG conformance control after polymer flooding) and Shengli oil field (PPG-surfactant flooding after polymer flooding) are used to check the reliability of the model. Combination of preformed gel particles, polymers and surfactants due to the deformation, swelling, and physicochemical properties of gel particles can mobilize the trapped oil through the porous media to enhance oil recovery factor by blocking the high permeable channels. As a result, PPG conformance control plays an essential role in oil recovery enhancement. Furthermore, experimental data of PPG/polymer/surfactant flooding in the Shengli field and its comparison with the proposed model indicated that the model and experimental field data are in a good agreement. Consequently, the coupled model of surfactant and PPG flooding after polymer flooding performances has led to more recovery factor rather than the basic chemical recovery techniques.

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