A Proposed Method for Simulation of Rate-Controlled Production Valves for Reduced Water Cut

2021 ◽  
pp. 1-16
Author(s):  
Ali Moradi ◽  
Britt M. E. Moldestad
Keyword(s):  
Multiphase Flow ◽  
Pid Controller ◽  
Horizontal Well ◽  
Oil Production ◽  
Well Completion ◽  
Autonomous Behavior ◽  
Water Breakthrough ◽  
Rate Controlled ◽  
Water Cut ◽  
D 12

Summary In recent years, the advancement of horizontal-well technology has played a major role in making oil production economically feasible from many reservoirs. One of the major problems that can reduce the efficiency of using horizontal wells is gas and water coning caused by the heel-toe effect and heterogeneity along the well. To tackle this problem, Equinor’s autonomous inflow-control device (ICD) (AICD), known as rate-controlled production (RCP) valves, is widely used today. RCP valves can effectively delay the early water breakthrough and partially choke back water autonomously after water breakthrough. To fulfill a suitable design of a long horizontal well with the RCP completion, a detailed understanding of multiphase-flow behavior from the reservoir pore to the wellbore and production tubing is needed. Coupling a dynamic multiphase-flow simulator such as the OLGASM (Schlumberger Limited, Sugar Land, Texas, USA) simulator with the near-wellbore reservoir module such as the OLGA ROCX module provides a robust tool for achieving this purpose. However, there is no predefined option in the OLGA simulator for implementing the autonomous behavior of the RCP valves directly. Therefore, creating a model of oil production by considering well completion with the RCP valves in the OLGA simulator is challenging. In the previous works, this has been performed by using the Proportional Integral Derivative (PID) Controller option in the OLGA simulator, which controls the opening of an equivalent orifice valve according to the fixed value of the water cut. However, because of the performance of the PID Controller using a fixed setpoint and the difficulties in properly tuning the PID Controller, choosing this option leads to a large degree of inaccuracy in the simulation models. In this paper, by proposing a novel method with a developed mathematical model and a control function for the RCP valves, the autonomous behavior of these valves is implemented in the OLGA simulator. In this new approach, the control signals are calculated using the variation of water cut and introduced to the OLGA simulator through the Table Controller option instead of the PID Controller. The presented approach in this paper can be used for the simulation of water-cut (or gas/oil-ratio) reduction potential of all RCP-type AICDs in reservoirs with different characteristics. However, to explain the procedure of this approach in detail, the near-well oil production from Well 16/2-D-12 in the Johan Sverdrup Field (JSF) considering RCP completion is modeled as a case study. In this study, the simulation model is developed using one of the commonly used types of RCP valves called the TR7 RCP valve. Version 2016.1.1 of the OLGA simulator/ROCX module is used (Schlumberger 2016). According to the simulation results, compared with using ICDs, by the completion of Well 16/2-D-12 with RCPs, the water cut, water-flow rate, and accumulated water production can be reduced by 2.9, 13.3, and 12.1%, respectively, after 750 days. The results also showed that by using the proposed approach, the autonomous behavior of the RCP valves according to the water-cut variations can be appropriately implemented in the OLGA simulator. This can help engineers and researchers to achieve a better design of a long horizontal well using the RCP completion. Consequently, using this approach can be beneficial for improving technology, optimizing production, minimizing risk, and reducing costs in oil recovery.

scholarly journals Comparison Between Homogenous and Heterogeneous Reservoirs: A Parametric Study of Water Coning Phenomena

2021 ◽  
Vol 5 (1) ◽  
pp. 119-131
Author(s):  
Frzan F. Ali ◽  
Maha R. Hamoudi ◽  
Akram H. Abdul Wahab
Keyword(s):  
Production Rate ◽  
Oil Production ◽  
Water Production ◽  
Effective Parameters ◽  
Radial Cross Section ◽  
Heterogeneous Reservoirs ◽  
Water Breakthrough ◽  
Water Coning ◽  
Water Cut ◽  
Reservoir Simulator

Water coning is the biggest production problem mechanism in Middle East oil fields, especially in the Kurdistan Region of Iraq. When water production starts to increase, the costs of operations increase. Water production from the coning phenomena results in a reduction in recovery factor from the reservoir. Understanding the key factors impacting this problem can lead to the implementation of efficient methods to prevent and mitigate water coning. The rate of success of any method relies mainly on the ability to identify the mechanism causing the water coning. This is because several reservoir parameters can affect water coning in both homogenous and heterogeneous reservoirs. The objective of this research is to identify the parameters contributing to water coning in both homogenous and heterogeneous reservoirs. A simulation model was created to demonstrate water coning in a single- vertical well in a radial cross-section model in a commercial reservoir simulator. The sensitivity analysis was conducted on a variety of properties separately for both homogenous and heterogeneous reservoirs. The results were categorized by time to water breakthrough, oil production rate and water oil ratio. The results of the simulation work led to a number of conclusions. Firstly, production rate, perforation interval thickness and perforation depth are the most effective parameters on water coning. Secondly, time of water breakthrough is not an adequate indicator on the economic performance of the well, as the water cut is also important. Thirdly, natural fractures have significant contribution on water coning, which leads to less oil production at the end of production time when compared to a conventional reservoir with similar properties.

scholarly journals Water Breakthrough Shape Description of Horizontal Wells in Bottom-Water Reservoir

2014 ◽  
Vol 2014 ◽  
pp. 1-9
Author(s):  
Shijun Huang ◽  
Baoquan Zeng ◽  
Fenglan Zhao ◽  
Linsong Cheng ◽  
Baojian Du
Keyword(s):  
Physical Model ◽  
Horizontal Well ◽  
Bottom Water ◽  
Water Reservoir ◽  
Horizontal Wells ◽  
Analysis Model ◽  
Heterogeneous Reservoir ◽  
Water Breakthrough ◽  
Original Oil In Place ◽  
Water Cut

Horizontal wells have been applied in bottom-water reservoir since their advantages were found on distribution of linear dropdown near wellbore, higher critical production, and more OOIP (original oil in place) controlled. In the paper, one 3D visible physical model of horizontal physical model is designed and built to simulate the water cresting process during the horizontal well producing and find water breakthrough point in homogenous and heterogeneous reservoir with bottom water. Water cresting shape and water cut of horizontal well in between homogenous and heterogeneous reservoir are compared on the base of experiment’s result. The water cresting pattern of horizontal well in homogeneous reservoir can be summarized as “central breakthrough, lateral expansion, thorough flooding, and then flank uplifting.” Furthermore, a simple analysis model of horizontal well in bottom water reservoir is established and water breakthrough point is analyzed. It can be drawn from the analysis result that whether or not to consider the top and bottom border, breakthrough would be located in the middle of horizontal segment with equal flow velocity distribution.

A Successful Application of Continuous Pack-Off Technology to Water Shutoff Recompletion for High-WCT Gravel-Packed Horizontal Well

2021 ◽  
Author(s):  
An Jiang ◽  
Yunpeng Li ◽  
Xing Liu ◽  
Fengli Zhang ◽  
Tianhui Wang ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Axial Flow ◽  
High Water ◽  
Bohai Bay ◽  
Horizontal Section ◽  
Well Completion ◽  
Water Shutoff ◽  
Sand Control ◽  
High Water Cut ◽  
Water Cut

Abstract Objectives/Scope Controlling the excessive water production from the high water cut gravel packing horizontal well is a challenge. The approach which uses regular packers or packers with ICD screens to control the unwanted water does not function well. This is mainly because of the length limitation of packers which will make the axial flow resistance insufficient. Methods, Procedures, Process In this paper, a successful case that unwanted water is shutoff by using continuous pack-off particles with ICD screens (CPI) in the whole horizontal section in an offshore oilfield of Bohai bay is presented. The reservoir of this case is the bottom-water high viscosity reservoir. The process is to run 2 3/8" ICD screen string into the 4" screen string originally in place, then to pump the pack-off particles into the annulus between the two screens, and finally form the 360m tightly compacted continuous pack-off particle ring. Results, Observations, Conclusions The methodology behind the process is that the 2-3/8" ICD screens limit the flow rate into the pipes as well as the continuous pack-off particle ring together with the gravel ring outside the original 4" screens to prevent the water channeling into the oil zone along the horizontal section. This is the first time this process is applied in a high water cut gravel packed horizontal well. After the treatment, the water rate decreased from 6856BPD to 836.6BPD, the oil rate increased from 44BPD to 276.8BPD. In addition, the duration of this performance continued a half year until March 21, 2020. Novel/Additive Information The key of this technology is to control the unwanted water by using the continuous pack-off particles instead of the parkers, which will bring 5 advantages, a) higher efficiency in utilizing the production interval; b) no need to find the water source and then fix it; c) the better ability to limit the axial flow; d) effective to multi-WBT (water break though) points and potential WBT points; e) more flexible for further workover. The technology of this successful water preventing case can be reference to other similar high water cut gravel packed wells. Also, it has been proved that the well completion approach of using CPI can have good water shutoff and oil incremental result. Considering the experiences of historical applications, CPI which features good sand control, water shutoff and anti-clogging is a big progress compared to the current completion technologies.

The Opportunities and Challenges of Preformed Particle Gel in Enhanced Oil Recovery

2020 ◽  
Vol 13 (4) ◽  
pp. 290-302
Author(s):  
Imran Akbar ◽  
Zhou Hongtao
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Oil Production ◽  
Silica Nanoparticle ◽  
Preformed Particle Gel ◽  
Water Breakthrough ◽  
Secondary Recovery ◽  
Water Cut ◽  
Preformed Particle Gels ◽  
Future Work

Enhanced Oil Recovery (EOR), is a technique that has been used to recover the remaining oil from the reservoirs after primary and secondary recovery methods. Some reservoirs are very complex and require advanced EOR techniques that containing new materials and additives in order to produce maximum oil in economic and environmentally friendly manners. Because of EOR techniques, in this work previous and current challenges have been discussed, and suggested some future opportunities. This work comprises the key factors, such as; transport of Preformed Particle Gels (PPGs), Surface wettability and conformance control that affect the efficiency of PPGs. The conduits, fractures, fracture-like features and high permeability streaks are the big challenges for EOR, as they may cause early water breakthrough and undesirable water channeling. Hence, the use of PPGs is one of the exclusive commercial gel inventions, which not only increases the oil production but also decreases the water cut during the oil production. Moreover, different studies regarding PPG, surfactants, and Silica nanoparticle applications, such as the effect of salinity, particle size, swelling ratio, gel strength, wettability, and adsorption were also discussed. Future work is required in order to overcome the conformance problems and increase the oil recovery.

Evaluating Water Coning Control for Horizontal Well in Bottom-Water Sandstone Reservoirs by Numerical Method

2012 ◽  
Vol 524-527 ◽  
pp. 292-296
Author(s):  
Rong Wang ◽  
Kui Zhang ◽  
Yong Gang Duan ◽  
Ting Kuan Cao
Keyword(s):  
Horizontal Well ◽  
Bottom Water ◽  
Negative Impact ◽  
Oil Production ◽  
High Water ◽  
Control Effect ◽  
Water Coning ◽  
Sandstone Reservoirs ◽  
High Water Cut Stage ◽  
Water Cut

Horizontal well is the main technology to develop bottom-water sandstone reservoirs. Water coning has a significant influence on development effect, and shut-in coning control is one of coning suppression methods. Based on the geological model of a given oilfield, this paper has made an evaluation of water coning control by numerical simulation. It can be concluded that the method of shut-in coning control is effective for low water cut wells. When shutting in, the lower the water cut is, the greater decline extent of water cut can be obtained and the higher cumulative oil production can be achieved after well reopening. The longer the close time is, the better water coning control effect can be acquired, however it will affect oil production undoubtly. When horizontal well enters into high water cut stage, shut-in coning control not only has almost no effect, but also has a negative impact on the normal oil production.

Application of Autonomous Inflow Control Valve AICV 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 Shabibi ◽  
Ameera Harrasi ◽  
Tejas Kalyani ◽  
...  
Keyword(s):  
Control Valve ◽  
Oil Production ◽  
Cost Effective ◽  
High Water ◽  
Water Production ◽  
Sultanate Of Oman ◽  
Viscous Oil ◽  
Water Breakthrough ◽  
Reservoir Conditions ◽  
Water Cut

Abstract One of the largest clastic reservoir fields in the Sultanate of Oman has been discovered in 1980 and put 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. Due to large fluid mobility contrast, the fields have experienced in pre-mature water breakthrough that has resulted in very high-water cuts. The average field water cut for open hole horizontal well after 6-9 months of production is over 94%. This paper details a 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 while producing oil 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, AICV's performance is superior due to its advanced design based on both Hagen-Poiseuille and Bernoulli's principles. This paper describes a comprehensive AICV completion design workflow that was developed across a multi-disciplinary team. Some of the initial wells completed with AICV has shown the benefit of accelerating oil production of over 30,000 bbls within the first few months of installation. Many wells started with 5-10 % water cut and are still producing with low water cut and higher oil production. The operator has approved AICV technology based on techno-commercial analysis and its positive impact on the project such as accelerated oil production and lower cost of water handling at the surface. AICV also helped in mitigating the facility constraints of handling produced water which resulted in reduce OPEX as allow the operator continued to drill horizontal wells. At the time of writing this paper, the operator has completed several dozen wells in the field with AICV technology and has an aggressive long term plan to complete several new and old wells. Finally, this paper also discusses in detail the comparative analysis of AICV wells for different subsurface conditions and share some 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 is a cost-effective field-proven technology for the water shut-off application. Due to its ability to autonomously identify and shut off water and gas production, the AICV technology has been approved to use as full fields implementation and in other fields. Field Background and Reservoir/Production challenges The operator produces around nine barrels of water against each produced barrel of oil. In general, the water produces to the surface with hydrocarbons contains many chemicals, which are usually not environmentally friendly and required additional treatment which increases the disposal cost. The Operator was looking for a cost-effective and proven technology that can control/shut off water production and improve oil production. The fields have a strong bottom aquifer and heterogeneous reservoir properties, such as permeability and downhole water saturation profiles. The challenge with matured brownfields, typically newly drilled wells will have pre-mature water breakthrough within few months of production. The fields have a highly viscous oil, with viscosity ranges from 200 cP up to 2000 cp at downhole conditions, thus creating a high mobility contrast between the oil and water, causing water fingering and coning at an early stage of production. These production challenges cause a significant recoverable oil left in the reservoir i.e. bypassed oil. Furthermore, excessive surface water production affects the integrated production system back pressures and flow, as well as an individual well's dynamics and pump efficiencies. This also has a significant downstream impact, where substantial investment is needed to handle, treat, and dispose of the water. Reducing these water volumes at the surface adds up to a tangible reduction in OPEX for water processing as well as environmentally friendly and assist the reservoir to maintain the reservoir pressure and energy by keeping the water in the reservoir. (Hilal et al 1997, Hassasi et al 2020)

scholarly journals Numerical Study of Single Well Vapor Extraction Process

2016 ◽  
Vol 2016 ◽  
pp. 1-9 ◽  
Author(s):  
Milad Rahnema ◽  
Hamed Rahnema ◽  
Marcia D. Mcmillan ◽  
Ali Reza Edrisi ◽  
Hamid Rahnema
Keyword(s):  
Horizontal Well ◽  
Numerical Study ◽  
Early Time ◽  
Oil Production ◽  
Extraction Process ◽  
Injection Rate ◽  
Vapor Extraction ◽  
Oil Viscosity ◽  
Well Completion ◽  
Single Well

Vapor extraction (Vapex) is an emerging technology to produce heavy oil and bitumen from subsurface formations. Single well (SW) Vapex technique uses the same concept of Vapex process but only with one horizontal well. In this process solvent is injected from the toe of the horizontal well with oil production at the heel section. The main advantage of SW-Vapex process lies in the economic saving and applicability in problematic reservoirs, where drilling of two horizontal wells is impractical. The performance of SW-Vapex seems to be comparable with dual horizontal Vapex process using proper optimization schemes. This study is grouped into two sections: (i) a screening study of early time operating performance of SW-Vapex and (ii) a sensitivity analysis of the effect of the reservoir and well completion parameters. Simulation results show that solvent injection rate can be optimized to improve oil production rate. Higher injection rates may not necessarily lead to increase in production. This study confirms that SW-Vapex process is very ineffective in reservoirs with high oil viscosity (more than 1,500 cp) and thin formations (less than 10 m).

Performance of a Horizontal Well in Bounded Reservoir Subject to Edge Water Drive

2013 ◽  
Vol 824 ◽  
pp. 365-372
Author(s):  
D.O. Onaiwu ◽  
E. Steve Adewole ◽  
O.A. Olafuyi
Keyword(s):  
Horizontal Well ◽  
Oil Production ◽  
Rapid Decline ◽  
Dimensionless Time ◽  
Fluid Movement ◽  
Well Completion ◽  
Dimensionless Pressure ◽  
Well Design ◽  
Well Spacing ◽  
Infinite Conductivity

When a reservoir is subject to edge water drive mechanism, well completion for the purpose of optimizing oil production becomes a critical objective. Achieving this objective will require a comprehensive knowledge of fluid movement in the reservoir. Effective well spacing and design, production or injection, transient test analyses possibilities and rate scheduling are additional benefits that can be derived from knowledge of fluid movement and dynamics. Source and greens functions are utilized in deriving the appropriate dimensionless pressure expressions for the reservoir system. Finally, dimensionless pressure derivatives are computed based on the dimensionless pressure expressions. Two-edged lateral water encroachment pattern is assumed for a centrally located horizontal well, occurring both at the toe and at the heel of the well. Influences of both reservoir and wellbore properties are investigated for infinite conductivity wellbore condition. Results show on the derivative that, flow is characterized first by infinite acting flow (constant value of 0.5) before a mandatory rapid decline to zero for all well and reservoir dimensions considered. The period of infinite activity, that is, period of clean oil production, is extended if the reservoir is much larger than the length of the well. Furthermore, dimensionless time of attainment of steady state for all well design is strongly dependent on the reservoir external extent and reservoir anisotropy under constant rate regime.

scholarly journals Correlation for Predicting Water Breakthrough Time in Thin Oil Rim Reservoirs in the Niger Delta

2018 ◽  
Vol 6 (3) ◽  
Author(s):  
Anietie Okon ◽  
Dulu Appah ◽  
Julius Akpabio
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Coefficient Of Determination ◽  
Reservoir Model ◽  
Breakthrough Time ◽  
Well Completion ◽  
Water Breakthrough ◽  
Oil Rim

In the Niger Delta, available correlations to predict water breakthrough time in thin oil rim reservoirs are based on generic reservoir models and/or experimental design approach. This approach had not considered the heterogeneity of the reservoir. Thus, the prediction of these available correlations for thin oil rim reservoirs in the Niger Delta is in doubt, considering the sensitive nature of developing thin oil rim reservoirs. Then, a correlation for water breakthrough time (tbt) was developed based on integrated reservoir model of thin oil rim reservoir in the Niger Delta. The obtained result indicated that the developed correlation predicted 1652.72 days compared to the actual Oilfield breakthrough time of 1653 days (about 4.53 years). Also, sensitivity study showed that the developed correlation and the integrated reservoir model predictions of oil production rate (qo), fractional well penetration (hp/h) and height above perforation-oil column (hap/h) on the water breakthrough time (tbt) were close and resulted in coefficient of determination (R2) of 0.9697, 0.8597 and 0.9553, respectively. Furthermore, the results depicted that water coning breakthrough time (tbt) depends directly on oil production rate (q) and well completion parameters: fractional well penetration (hp/h) and height above perforation (hap). Hence, to delay early water breakthrough in thin oil rim reservoirs, these completion parameters are consideration in vertical wells to achieve optimum oil recovery. Also, the developed correlation can be used as a quick and robust tool to predict water breakthrough time of thin oil rim reservoirs in the Niger Delta.

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