Application of the Jet Pump to the Slim Hole Production Wells at Onshore Thailand

2021 ◽  
Author(s):  
Ryujiro Ishihara ◽  
Naohide Higuchi ◽  
Yohei Mikami
Keyword(s):  
Oil Recovery ◽  
Oil Field ◽  
Recovery Factor ◽  
Jet Pump ◽  
Coiled Tubing ◽  
Artificial Lift ◽  
Production Wells ◽  
Pros And Cons ◽  
Main Production ◽  
Integrity Risk

Abstract This is a case study to establish the positive result of an artificial lift application of the jet pump (JP) system using the coiled tubing (CT) and the macaroni tubing (MT). It is applied to the monobore completions for the slim-hole production wells on BURAPA-A oil field, onshore Thailand, implemented by Siam Moeco Ltd. (SML, Affliated Company of Mitsui Oil Exploration Co., Ltd.). As a result of the JP introduction, the resulting production decline rate was lower and the recovery factor more than doubled, which extended field life longer than expected. SML succeeded in discovering the method to minimize the capital cost while maximizing the oil recovery with the JP system. This method has given us the chance to conduct a smaller-scale well intervention operation with only minor modification of the wellhead. We believe that it is an adequate artificial lift application for the small-size oil field. Some important lessons for the small pipe size operations were learned in this process. A pin-hole leak was detected in the CT for the main production well due to erosion and corrosion by continuous high-pressure pumping for around two years after the installation of the JP completion. After reviewing the new completion design, the type of deployment pipe was converted to the MT, which is thicker and has higher integrity than the CT. Consequently, there have been no integrity issues for the deployment pipes since the production was resumed with the new completion. In addition, using the multi finger caliper tool, it was detected that the thickness of the production tubing at the jetting area was significantly eroded, showing that the JP system has the possibility to risk the integrity for the outer string. The JP completion is a validated technology to apply for the slim-hole monobore completions to increase the recovery factor and minimize the implementation cost. In addition, the well integrity risk by the JP application to the slim-hole monobore completions was revealed, and new insights were gained, resulting in some pros and cons comparing the two types of the deployment pipes (CT & MT).

Successful Field Pilot of In-Depth Colloidal Dispersion Gel (CDG) Technology in Daqing Oilfield

2006 ◽  
Vol 9 (06) ◽  
pp. 664-673 ◽  
Author(s):  
Harry L. Chang ◽  
Xingguang Sui ◽  
Long Xiao ◽  
Zhidong Guo ◽  
Yuming Yao ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Colloidal Dispersion ◽  
Oil Field ◽  
Sweep Efficiency ◽  
Profile Modification ◽  
Production Wells ◽  
Daqing Oil Field ◽  
Incremental Oil Recovery ◽  
Water Cut ◽  
Weak Gels

Summary The first large-scale colloidal dispersion gel (CDG) pilot test was conducted in the largest oil field in China, Daqing oil field. The project was initiated in May 1999, and injection of chemical slugs was completed in May 2003. This paper provides detailed descriptions of the gel-system characterization, chemical-slug optimization, project execution, performance analysis, injection facility design, and economics. The improvements of permeability variation and sweep efficiency were demonstrated by lower water cut, higher oil rate, improved injection profiles, and the increase of the total dissolved solids (TDS) in production wells. The ultimate incremental oil recovery (defined as the amount of oil recovered above the projected waterflood recovery at 98% water cut) in the pilot area would be approximately 15% of the original oil in place (OOIP). The economic analysis showed that the chemical costs were approximately U.S. $2.72 per barrel of incremental oil recovered. Results are presented in 15 tables and 8 figures. Introduction Achieving mobility control by increasing the injection fluid viscosity and achieving profile modification by adjusting the permeability variation in depth are two main methods of improving the sweep efficiency in highly heterogeneous and moderate viscous-oil reservoirs. In recent years (Wang et al. 1995, 2000, 2002; Guo et al. 2000), the addition of high-molecular-weight (MW) water-soluble polymers to injection water to increase viscosity has been applied successfully in the field on commercial scales. Weak gels, such as CDGs, formed with low-concentration polymers and small amounts of crosslinkers such as the trivalent cations aluminum (Al3+) and chromium (Cr3+) also have been applied successfully for in-depth profile modification (Fielding et al. 1994; Smith 1995; Smith and Mack 1997). Typical behaviors of CDGs and testing methods are given in the literature (Smith 1989; Ranganathan et al. 1997; Rocha et al. 1989; Seright 1994). The giant Daqing oil field is located in the far northeast part of China. The majority of the reservoir belongs to a lacustrine sedimentary deposit with multiple intervals. The combination of heterogeneous sand layers [Dykstra-Parsons (1950) heterogeneity indices above 0.5], medium oil viscosities (9 to 11 cp), mild reservoir temperatures (~45°C), and low-salinity reservoir brines [5,000 to 7,000 parts per million (ppm)] makes it a good candidate for chemical enhanced-oil-recovery processes. Daqing has successfully implemented commercial-scale polymer flooding (PF) since the early 1990s (Chang et al. 2006). Because the PF process is designed primarily to improve the mobility ratio (Chang 1978), additional oil may be recovered by using weak gels to further improve the vertical sweep. Along with the successes of PF in the Daqing oil field, two undesirable results were also observed:high concentrations of polymer produced in production wells owing to the injection of large amounts of polymer (~1000 ppm and 50% pore volume) andthe fast decline in oil rates and increase in water cuts after polymer injection was terminated. In 1997, a joint laboratory study between the Daqing oil field and Tiorco Inc. was conducted to investigate the potential of using the CDG process, or the CDG process with PF, to further improve the recovery efficiency, lower the polymer production in producing wells, and prolong the flood life. The joint laboratory study was completed in 1998 with encouraging results (Smith et al. 2000). Additional laboratory studies to further characterize the CDG gellation process, optimize the formulation, and investigate the degradation mechanisms were conducted in the Daqing field laboratories before the pilot test. A simplistic model was used to optimize the slug designs and predict incremental oil recovery. Initial designs called for a 25% pore volume (Vp) CDG slug with 700 ppm polymer and the polymer-to-crosslinker ratio (P/X) of 20 in a single inverted five-spot patten. Predicted incremental recovery was approximately 9% of OOIP.

scholarly journals Status Quo of a CO2-Assisted Steam-Flooding Pilot Test in China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Zongyao Qi ◽  
Tong Liu ◽  
Changfeng Xi ◽  
Yunjun Zhang ◽  
Dehuang Shen ◽  
...  
Keyword(s):  
Field Test ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Oil Field ◽  
Drainage Pattern ◽  
Steam Flooding ◽  
Production Wells ◽  
Water Cut ◽  
Production Dynamics

It is challenging to enhance heavy oil recovery in the late stages of steam flooding. This challenge is due to reduced residual oil saturation, high steam-oil ratio, and lower profitability. A field test of the CO2-assisted steam flooding technique was carried out in the steam-flooded heavy oil reservoir in the J6 block of the Xinjiang oil field (China). In the field test, a positive response to the CO2-assisted steam flooding treatment was observed, including a gradually increasing heavy oil production, an increase in the formation pressure, and a decrease in the water cut. The production wells in the test area mainly exhibited four types of production dynamics, and some of the production wells exhibited production dynamics that were completely different from those during steam flooding. After being flooded via CO2-assisted steam flooding, these wells exhibited a gravity drainage pattern without steam channeling issues, and hence, they yielded stable oil production. In addition, emulsified oil and CO2 foam were produced from the production well, which agreed well with the results of laboratory-scale tests. The reservoir-simulation-based prediction for the test reservoir shows that the CO2-assisted steam flooding technique can reduce the steam-oil ratio from 12 m3 (CWE)/t to 6 m3 (CWE)/t and can yield a final recovery factor of 70%.

Low-Cost Development Plan Optimization for a Polish Oil Field

2021 ◽  
Author(s):  
Daniel Podsobinski ◽  
Roman Madatov ◽  
Bartlomiej Kawecki ◽  
Grzegorz Paliborek ◽  
Piotr Wójcik ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Capital Expenditure ◽  
Oil Production ◽  
Oil Field ◽  
Oil Fields ◽  
Development Plan ◽  
Recovery Factor ◽  
Co2 Injection ◽  
Development Scenarios ◽  
Injection Water

Abstract In Poland there are approximately 60 oil fields located in different geological structures. Most of these fields have been producing for several years to several dozen years, and now require redefining of the development plan by utilizing an improved oil recovery (IOR) or enhanced oil recovery (EOR) method to achieve a higher oil recovery factor. Here we present the redevelopment plan for the Polish Main Dolomite oil field, that aimed to optimize and maximize the oil recovery factor. Considering all available geological and reservoir data, both a static and dynamic model were built and calibrated for three separate reservoirs connected to the same production facility. Then the comprehensive study was performed where different development scenarios was considered and tested using reservoir numerical simulation. The proposed redevelopment scenarios included excessive gas reinjection to the main reservoir, additional high-nitrogen (N2) gas injection from a nearby gas reservoir (87% of N2), carbon dioxide (CO2) injection, water injection, polymer injection, water-alternating-gas (WAG), well stimulation, and a combination of these methods. Development plans assumes also drilling new injection and production wells and converting existing producers to gas or water injectors. The key component in development scenarios was to arrest the pressure decline from the main field and decrease the gas/oil ratio (GOR). An additional challenge was to implement in the simulation model all key assumptions behind various development scenarios, while also taking into account specific facility constraints and simultaneously handling separate reservoirs that are connected to the same facility, and hence affecting each other. From numerous scenarios, the scenario that requires the least number of new wells was selected and further optimized. It considers the drilling of only one new producer, one new water injector, and conversion of some currently producing wells to gas and water injectors. The location of the proposed well and the amount of injection fluids was optimized to achieve the highest oil recovery factor and to postpone gas and water breakthrough as much as possible. The optimized case that assumes low investments is expected to improve incremental oil production by 90% over No Further Actions Scenario. However, the study suggests the potential of more than tripling incremental oil production under a scenario with considerably higher expenditures. The improved case assumes drilling one more producer, four new water injectors, and injection of three times more water. The presented field optimization example highlights that in many existing Polish oil fields there is still a potential to reach higher oil recovery without considerable expenditures. However, to obtain more significant oil recovery improvement, higher capital expenditure is necessary. To facilitate the selection of the best development scenario, a detailed economic and risk analysis needs to be conducted.

Feasibility of Waterflooding for a Carbonate Oil Field Through Whole-Field Simulation Studies

2015 ◽  
Vol 137 (6) ◽  
Author(s):  
Wenting Yue ◽  
John Yilin Wang
Keyword(s):  
Oil Recovery ◽  
Injection Rate ◽  
Carbonate Reservoir ◽  
Oil Field ◽  
Improved Oil Recovery ◽  
Smackover Formation ◽  
Artificial Lift ◽  
Production History ◽  
Current Production ◽  
The Impact

The carbonate oil field studied is a currently producing field in U.S., which is named “PSU” field to remain anonymity. Discovered in 1994 with wells on natural flow or through artificial lift, this field had produced 17.8 × 106 bbl of oil to date. It was noticed that gas oil ratio had increased in certain parts and oil production declined with time. This study was undertaken to better understand and optimize management and operation of this field. In this brief, we first reviewed the geology, petrophysical properties, and field production history of PSU field. We then evaluated current production histories with decline curve analysis, developed a numerical reservoir model through matching production and pressure data, then carried out parametric studies to investigate the impact of injection rate, injection locations, and timing of injection, and finally developed optimized improved oil recovery (OIR) methods based on ultimate oil recovery and economics. This brief provides an addition to the list of carbonate fields available in the petroleum literature and also improved understandings of Smackover formation and similar analogous fields. By documenting key features of carbonated oil field performances, we help petroleum engineers, researchers, and students understand carbonate reservoir performances.

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.

scholarly journals CHANGE IN THE HYDROGEOCHEMICAL FIELD OF THE U1 HORIZON OF THE VERKH-TARSKOYE OIL FIELD IN THE PROCESS OF DEVELOPMENT

2021 ◽  
Vol 2 (1) ◽  
pp. 271-281
Author(s):  
Anastasiya S. Faustova ◽  
Dmitry A. Novikov ◽  
Svetlana A. Pavlova ◽  
Anatoliy V. Chernykh ◽  
Fedor F. Dultsev ◽  
...  
Keyword(s):  
Produced Water ◽  
Comprehensive Analysis ◽  
Oil Field ◽  
Oil Reservoir ◽  
Joint Operation ◽  
Production Wells ◽  
Cumulative Production ◽  
Main Production ◽  
Field Information ◽  
Water Cut

The results of a comprehensive analysis of geological and field information are presented in order to assess changes in the hydrogeochemical field of the oil reservoir of the U horizon of the Verkh-Tarskoye oil field during its development in the period from 1994 to 2021. The main production facility is at the IV stage of declining production. The water cut of the production wells stock reaches 98% with cumulative production of 14.86 million tons (as of May 1, 2021). Since 2015, there has been an increase in the TDS of produced water, which is explained by the processes of their mixing with circuit waters along the periphery of the reservoir with a decrease in reservoir pressure and more saline waters of the U horizon, supplied during joint operation.

Experimental Investigation of a Viscous Surfactant and Surfactant Flooding to Enhance Oil Recovery

2009 ◽  
Author(s):  
Omid Arjmand ◽  
Jalal Foroozesh ◽  
Ali Reza Roostaee ◽  
Shahaboddin Ayatollahi
Keyword(s):  
Oil Recovery ◽  
Terephthalic Acid ◽  
Recovery Process ◽  
Oil Field ◽  
Recovery Factor ◽  
Water Flooding ◽  
Surfactant Flooding ◽  
Chemical Solutions ◽  
Secondary Oil Recovery ◽  
Enhance Oil Recovery

A chemical Enhanced Oil Recovery (EOR) process receives more attentions nowadays. Crude Terephthalic Acid (CTA) as a chemical compound is used for flooding here as an alternative to the traditional hydrolyzed polyacryl amide (HPAM). Crude Oil samples from an Iranian oil field were used during the flooding tests. Sand packed models using two different sizes of sand mainly 50 and 100 meshes were employed in this investigation. A comparison between water flooding and CTA flooding as a secondary oil recovery process revealed that the recovery was improved by 10% when CTA was used. The effect of various injection rates and different concentration of chemical solutions on the recovery factor have been checked. Besides, experimental results improved the surfactant behavior of the CTA solution in water. Moreover, at tertiary state, Sodium Dodocyl Sulfate (SDS) as an anionic surfactant was flooded. Experiments showed that recovery factor increased by 5% OOIP while using SDS.

scholarly journals The effect of gravity drainage mechanism on oil recovery by reservoir simulation; a case study in an Iranian highly fractured reservoir

2021 ◽  
Author(s):  
K. Zobeidi ◽  
M. Mohammad-Shafie ◽  
M. Ganjeh-Ghazvini
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Fractured Reservoirs ◽  
Saturation Pressure ◽  
Oil Field ◽  
Recovery Factor ◽  
Real Field ◽  
Gravity Drainage ◽  
Special Importance ◽  
Fractured Reservoir

AbstractA comprehensive reservoir simulation study was performed on an oil field that had a wide fracture network and could be considered a typical example of highly fractured reservoirs in Iran. This field is located in southwest of Iran in Zagros sedimentary basin among several neighborhood fields with relatively considerable fractured networks. In this reservoir, the pressure drops below the saturation pressure and causes the formation of a secondary gas cap. This can help to better assess the gravity drainage phenomenon. We decided to investigate and track the effect of gravity drainage mechanism on the recovery factor of oil production in this field. In this study, after/before the implementation of gas injection scenarios with different discharges, the contribution of gravity drainage mechanism to the recovery factor was found more than 50%. Considering that a relatively large number of studies have been conducted on this field simultaneously with the growth of information from different aspects and this study is the last and most comprehensive study and also the results are extracted from real field data using existing reservoir simulators, it is of special importance and can be used by researchers.

scholarly journals Application of Systematic Approach for Fast Oil Production Enhancement-Case Studies

2014 ◽  
Vol 5 (1) ◽  
pp. 182-204
Author(s):  
Seyed Mahdia Motahari ◽  
Mahdi Nadri Pari
Keyword(s):  
Economic Analysis ◽  
Oil Recovery ◽  
Oil Production ◽  
Oil Field ◽  
Time To Failure ◽  
Production Network ◽  
Improved Oil Recovery ◽  
Recovery Method ◽  
Full Field ◽  
Artificial Lift

   Full field studies and master development plans are time consuming and expensive tasks for any company to find optimum improved oil recovery method. Fast oil production enhancement is a method applied over existing assets resulting in fast increase in oil production in less expensive way. This approach consists of five steps as identification of source of production decline problem through evaluation of diagnostic tests, prioritizing different solutions for treating the problem, conceptual integrated modeling of reservoir and wells, production network optimization and economic analysis.    In this paper we elaborate and implement these five steps in an Iranian Oil Field with twenty wells. Firstly; we found that the production decline is due to poor well cleaning after stimulation and work over operation and also reservoir pressure decline leading to not having sufficient energy to push oil to the surface. Secondly; based on specifications of each well and pre-determined screening criteria; artificial lift methods were prioritized followed thirdly by conceptual modeling of first ranked artificial lift method which was electric submersible pump for first ranked wells. The fourth step was optimization of production network through sequential quadratic programming and lastly probabilistic economic analysis based on different ESP time to failure. The result of this study shows viability of application of ESP in this field in fast way.  

Artificial Lift Rigless Opportunity to Re-Activate the Inactive Wells Inventory an a Middle East Mega-Field After a Successful Pilot of a Best Practices and New Technology With Jet Pump

2021 ◽  
Author(s):  
Rodrigo A. Guzman ◽  
Tariq Abdulla Al Junaibi ◽  
Fouad Abdulsallam ◽  
Mohamed Elmaghraby Hewala ◽  
Hector Aguilar ◽  
...  
Keyword(s):  
New Technology ◽  
Scale Up ◽  
Oil Field ◽  
Jet Pump ◽  
Pump System ◽  
Pump Operation ◽  
Artificial Lift ◽  
Average Production ◽  
The Impact ◽  
Side Pocket

Abstract A Gulf oil operation company has been working to evaluate a rigless method of Artificial Lift System (ALS) suitable for its current assets and any future needs on ALS to minimize the impact of deferred production, and having the flexibility to bringing back the inactive string to production and act as a sustained production lift method. This paper describes a comprehensive study of the main objectives for a rigless Artificial Lift trial. The Rigless Jet Pump system was selected as one of the ALS fast implementation methods to activate the inactive wells. The trial was conducted in two inactive wells; across two different mega-fields, enabling both wells to produce stably and continuously with an average production rate of 650 BOPD. A thorough assessment was performed and the Rigless Jet Pump System was declared as a successful pilot providing confidence to scale up across all the company fields. The scale-up plans it will include 10 systems that can be rotated and applied where needed across all company fields. The trial implementation of the Rigless Jet Pump was evaluated based on supply and the connectivity in the field. This includes equipment mobilization (from the call-out time), availability of the field resources, the installation job, and up to the Surface Equipment connectivity plan. The evaluation also closely monitored the subsequence rig-up procedure and rigless deployment of the downhole equipment which was designed for installation straddled across an existing gas lift side pocket mandrel. Once surface and subsurface installation was completed, the wells were put on production to reactivate the inactive strings. Both wells were tested to confirm the achievement of a minimum of 80% of the designed production rates. The performance of the rigless activation of inactive wells using a jet pump has been proven successful. Both wells showed promising results while jet pump operation confirming a profitable alternative to accelerate production across fields toward achieving production mandates. The performance of the system delivered the Efficiency and Safety (HSE & Integrity) expected as part of the project KPI's. This novel practice for the Jet Pump System is linked to the rigless deployment and retrieval mechanism with topside equipment skid mounted for easy movement to other wells. This gives to the oil field operators an alternative and competitive edge over other modes of lift that required a workover program. The rigless method can be adapted to the existing in-active wells with SPM (side Pocket Mandrels) or without; by a tubing punch after a comprehensive integrity evaluation.

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