Unleashing Full Production Potential of Mature-Water Coning Sensitive-Oil Field through Simple Reservoir Simulation and Artificial Lift Installation

2019 ◽  
Author(s):  
M. Arief Salman Alfarizi ◽  
Agus Aryanto ◽  
Tejo Sukotrihadiyono ◽  
Farid Ghozali ◽  
Dwi Hudya Febrianto ◽  
...  
Keyword(s):  
Reservoir Simulation ◽  
Oil Field ◽  
Production Potential ◽  
Artificial Lift ◽  
Water Coning ◽  
Full Production

Numerical Simulation of Gas Lift Optimization Using Artificial Intelligence for a Middle Eastern Oil Field

2021 ◽  
Author(s):  
Mohammed Ahmed Al-Janabi ◽  
Omar F. Al-Fatlawi ◽  
Dhifaf J. Sadiq ◽  
Haider Abdulmuhsin Mahmood ◽  
Mustafa Alaulddin Al-Juboori
Keyword(s):  
Genetic Algorithm ◽  
Sensitivity Analysis ◽  
Middle Eastern ◽  
Optimization Technique ◽  
Injection Rate ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Artificial Lift ◽  
Gas Lift

Abstract Artificial lift techniques are a highly effective solution to aid the deterioration of the production especially for mature oil fields, gas lift is one of the oldest and most applied artificial lift methods especially for large oil fields, the gas that is required for injection is quite scarce and expensive resource, optimally allocating the injection rate in each well is a high importance task and not easily applicable. Conventional methods faced some major problems in solving this problem in a network with large number of wells, multi-constrains, multi-objectives, and limited amount of gas. This paper focuses on utilizing the Genetic Algorithm (GA) as a gas lift optimization algorithm to tackle the challenging task of optimally allocating the gas lift injection rate through numerical modeling and simulation studies to maximize the oil production of a Middle Eastern oil field with 20 production wells with limited amount of gas to be injected. The key objective of this study is to assess the performance of the wells of the field after applying gas lift as an artificial lift method and applying the genetic algorithm as an optimization algorithm while comparing the results of the network to the case of artificially lifted wells by utilizing ESP pumps to the network and to have a more accurate view on the practicability of applying the gas lift optimization technique. The comparison is based on different measures and sensitivity studies, reservoir pressure, and water cut sensitivity analysis are applied to allow the assessment of the performance of the wells in the network throughout the life of the field. To have a full and insight view an economic study and comparison was applied in this study to estimate the benefits of applying the gas lift method and the GA optimization technique while comparing the results to the case of the ESP pumps and the case of naturally flowing wells. The gas lift technique proved to have the ability to enhance the production of the oil field and the optimization process showed quite an enhancement in the task of maximizing the oil production rate while using the same amount of gas to be injected in the each well, the sensitivity analysis showed that the gas lift method is comparable to the other artificial lift method and it have an upper hand in handling the reservoir pressure reduction, and economically CAPEX of the gas lift were calculated to be able to assess the time to reach a profitable income by comparing the results of OPEX of gas lift the technique showed a profitable income higher than the cases of naturally flowing wells and the ESP pumps lifted wells. Additionally, the paper illustrated the genetic algorithm (GA) optimization model in a way that allowed it to be followed as a guide for the task of optimizing the gas injection rate for a network with a large number of wells and limited amount of gas to be injected.

Reservoir Simulation Modeling of the World's Largest Clastic Oil Field - The Greater Burgan Field, Kuwait

2014 ◽  
Author(s):  
E. Ma ◽  
S. Ryzhov ◽  
S. Gheorghiu ◽  
O. Hegazy ◽  
M. Banagale ◽  
...  
Keyword(s):  
Reservoir Simulation ◽  
Simulation Modeling ◽  
Oil Field

Rich-Gas Condensate Huff and Puff Process in High-Volume, Watered-Out, and Highly Viscous Heavy Oil Wells, Case Study in Iraq

2021 ◽  
Author(s):  
Xueqing Tang ◽  
Ruifeng Wang ◽  
Zhongliang Cheng ◽  
Hui Lu
Keyword(s):  
High Pressure ◽  
Heavy Oil ◽  
Oil Quality ◽  
Oil Wells ◽  
Gas Condensate ◽  
Oil Viscosity ◽  
Foamy Oil ◽  
Artificial Lift ◽  
Water Coning ◽  
The Dead

Abstract Halfaya field in Iraq contains multiple vertically stacked oil and gas accumulations. The major oil horizons at depth of over 10,000 ft are under primary development. The main technical challenges include downdip heavy oil wells (as low as 14.56 °API) became watered-out and ceased flow due to depleted formation pressure. Heavy crude, with surface viscosities of above 10,000 cp, was too viscous to lift inefficiently. The operator applied high-pressure rich-gas/condensate to re-pressurize the dead wells and resumed production. The technical highlights are below: Laboratory studies confirmed that after condensate (45-52ºAPI) mixed with heavy oil, blended oil viscosity can cut by up to 90%; foamy oil formed to ease its flow to the surface during huff-n-puff process.In-situ gas/condensate injection and gas/condensate-lift can be applied in oil wells penetrating both upper high-pressure rich-gas/condensate zones and lower oil zones. High-pressure gas/condensate injected the oil zone, soaked, and then oil flowed from the annulus to allow large-volume well stream flow with minimal pressure drop. Gas/condensate from upper zones can lift the well stream, without additional artificial lift installation.Injection pressure and gas/condensate rate were optimized through optimal perforation interval and shot density to develop more condensate, e.g. initial condensate rate of 1,000 BOPD, for dilution of heavy oil.For multilateral wells, with several drain holes placed toward the bottom of producing interval, operating under gravity drainage or water coning, if longer injection and soaking process (e.g., 2 to 4 weeks), is adopted to broaden the diluted zone in heavy oil horizon, then additional recovery under better gravity-stabilized vertical (downward) drive and limited water coning can be achieved. Field data illustrate that this process can revive the dead wells, well production achieved approximately 3,000 BOPD under flowing wellhead pressure of 800 to 900 psig, with oil gain of over 3-fold compared with previous oil rate; water cut reduction from 30% to zero; better blended oil quality handled to medium crude; and saving artificial-lift cost. This process may be widely applied in the similar hydrocarbon reservoirs as a cost-effective technology in Middle East.

A Superior Shale Oil EOR Method for the Permian Basin

2021 ◽  
Author(s):  
Robert Downey ◽  
Kiran Venepalli ◽  
Jim Erdle ◽  
Morgan Whitelock
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Simulation Modeling ◽  
Lower Cost ◽  
Oil Production ◽  
Oil Wells ◽  
Oil Well ◽  
Shale Oil ◽  
Permian Basin ◽  
Artificial Lift

Abstract The Permian Basin of west Texas is the largest and most prolific shale oil producing basin in the United States. Oil production from horizontal shale oil wells in the Permian Basin has grown from 5,000 BOPD in February, 2009 to 3.5 Million BOPD as of October, 2020, with 29,000 horizontal shale oil wells in production. The primary target for this horizontal shale oil development is the Wolfcamp shale. Oil production from these wells is characterized by high initial rates and steep declines. A few producers have begun testing EOR processes, specifically natural gas cyclic injection, or "Huff and Puff", with little information provided to date. Our objective is to introduce a novel EOR process that can greatly increase the production and recovery of oil from shale oil reservoirs, while reducing the cost per barrel of recovered oil. A superior shale oil EOR method is proposed that utilizes a triplex pump to inject a solvent liquid into the shale oil reservoir, and an efficient method to recover the injectant at the surface, for storage and reinjection. The process is designed and integrated during operation using compositional reservoir simulation in order to optimize oil recovery. Compositional simulation modeling of a Wolfcamp D horizontal producing oil well was conducted to obtain a history match on oil, gas, and water production. The matched model was then utilized to evaluate the shale oil EOR method under a variety of operating conditions. The modeling indicates that for this particular well, incremental oil production of 500% over primary EUR may be achieved in the first five years of EOR operation, and more than 700% over primary EUR after 10 years. The method, which is patented, has numerous advantages over cyclic gas injection, such as much greater oil recovery, much better economics/lower cost per barrel, lower risk of interwell communication, use of far less horsepower and fuel, shorter injection time, longer production time, smaller injection volumes, scalability, faster implementation, precludes the need for artificial lift, elimination of the need to buy and sell injectant during each cycle, ability to optimize each cycle by integration with compositional reservoir simulation modeling, and lower emissions. This superior shale oil EOR method has been modeled in the five major US shale oil plays, indicating large incremental oil recovery potential. The method is now being field tested to confirm reservoir simulation modeling projections. If implemented early in the life of a shale oil well, its application can slow the production decline rate, recover far more oil earlier and at lower cost, and extend the life of the well by several years, while precluding the need for artificial lift.

Production Optimization over 20% with Artificial Lift ESP Pilot Systems in Mature Oil Field, Case Study from Middle East

2014 ◽  
Author(s):  
Hector Aguilar ◽  
Aref Almarzooqi ◽  
Tarek Mohamed El Sonbaty ◽  
Leigber Villarreal
Keyword(s):  
Middle East ◽  
Production Optimization ◽  
Oil Field ◽  
Field Case ◽  
Artificial Lift

Against the Grain: Three Proppant Delivery Approaches That Buck the Status Quo

2021 ◽  
Vol 73 (01) ◽  
pp. 28-31
Author(s):  
Trent Jacobs
Keyword(s):  
Open Fracture ◽  
Horizontal Wells ◽  
Field Studies ◽  
Technical Conference ◽  
Oil Field ◽  
Permian Basin ◽  
Artificial Lift ◽  
Fracture Area ◽  
The Status ◽  
Conventional Oil

Pumping proppant down a wellbore is the easy part. Ensuring that the precious material does its job is another matter. A trio of field studies recently presented at the 2020 SPE Annual Technical Conference and Exhibition (ATCE) highlight in different ways how emerging technology and old-fashioned problem solving are moving the industry needle on proppant and conductivity control. These examples include the adoption of unconventional completion techniques in a conventional oil field in Russia and work to validate the use of small amounts of ceramic proppant in North Dakota’s tight-oil formations. Both studies seek to counter widely held assumptions about proppant conductivity. A third study details a recently developed chemical coating that Permian Basin producers are applying “on the fly” to sand before it is pumped downhole. The new adhesive material has found a niche in helping operators mitigate the amount of sand that returns to surface during flowback, a sectorwide issue that drives up completion costs and later may spell trouble for artificial lift systems. Disproving “The Overflush Paradigm” After conventional reservoirs are hydraulically fractured, both from vertical and horizontal wells, it has been standard practice for decades to treat the newly propped perforations with a gentle touch. The approach to this end is known as underflushing. When underflushing, the goal is to leave behind just a few barrels’ worth of proppant-laden slurry over the perforations before attempting to complete further stages. The motivation for this boils down to the need for an insurance policy against displacing the near-wellbore proppant pack and causing the open fracture face to pinch off before it ever has a chance to transmit hydrocarbons. Such carefulness comes at a price. Underflushing raises the risk of needing a cleanout before oil can flow optimally to surface. This not only delays the arrival of first oil, it means extra equipment and personnel are required. However, a more glaring downside to underflushing is that it appears to be an unnecessary precaution. The near-wellbore fracture area is, in fact, more robust than what conventional wisdom allows credit for.

Overcoming Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field

2021 ◽  
Vol 73 (03) ◽  
pp. 46-47
Author(s):  
Chris Carpenter
Keyword(s):  
Heavy Oil ◽  
Oil Field ◽  
Primary System ◽  
Artificial Lift ◽  
Short Period ◽  
Production History ◽  
Electrical Submersible Pump ◽  
Water Cut ◽  
Available Information ◽  
Offshore Oil

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201135, “Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field,” by Alexandre Tavares, Paulo Sérgio Rocha, SPE, and Marcelo Paulino Santos, Enauta, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition - Americas, 10-12 November. The paper has not been peer reviewed. Atlanta is a post-salt offshore oil field in the Santos Basin, 185 km southeast of Rio de Janeiro. The combination of ultradeep water (1550 m) and heavy, viscous oil creates a challenging scenario for electrical submersible pump (ESP) applications. The complete paper discusses the performance of an ESP system using field data and software simulations. Introduction From initial screening to define the best artificial-lift method for the Atlanta Field’s requirements, options such as hydraulic pumps, hydraulic submersible pumps, multiphase pumps, ESPs, and gas lift (GL) were considered. Analysis determined that the best primary system was one using an in-well ESP with GL as backup. After an initial successful drillstem test (DST) with an in-well ESP, the decision was made, for the second DST, to install the test pump inside the riser, near seabed depth. It showed good results; comparison of oil-production potential between the pump installed inside a structure at the seabed—called an artificial lift skid (ALS)—and GL suggested that the latter would prove uneconomical. The artificial lift development concept is shown in Fig. 1. ESP Design ESP sizing was performed with a commercial software and considered available information on reservoir, completion, subsea, and topsides. To ensure that the ESP chosen would meet production and pressure boosts required in the field, base cases were built and analyzed for different moments of the field’s life. The cases considered different productivity indexes (PI), reservoir pressures, and water production [and consequently water cut (WC)] as their inputs. The design considers using pumps with a best efficiency point (BEP) for water set at high flow rates (17,500 B/D for in-well and 34,000 B/D for ALS). Thus, when the pumps deal with viscous fluid, the curve will have a BEP closer to the current operating point. Design boundaries of the in-well ESP and the ALS are provided in the complete paper, as are some of the operational requirements to be implemented in the ESP design to minimize risk. Field Production History In 2014, two wells were drilled, tested, and completed with in-well ESP as the primary artificial lift method. Because of delays in delivery of a floating production, storage, and offloading vessel (FPSO), the backup (ALS) was not installed until January 2018. In May 2018, Atlanta Field’s first oil was achieved through ATL-2’s in-well ESP. After a few hours operating through the in-well ESP, it prematurely failed, and the ALS of this well was successfully started up. Fifteen days after first oil, ATL-3’s in-well ESP was started up, but, as occurred with ATL-2, failed after a short period. Its ALS was successfully started up, and both wells produced slightly more than 1 year in that condition.

Understanding ESP Performance Under High Viscous Applications and Emulsion Production

2021 ◽  
Author(s):  
Luiz Pastre ◽  
Jorge Biazussi ◽  
William Monte Verde ◽  
Antonio Bannwart
Keyword(s):  
High Viscosity ◽  
Field Application ◽  
Oil Field ◽  
Two Phase ◽  
Water Emulsion ◽  
Technical Requirements ◽  
Artificial Lift ◽  
Controlled Environments ◽  
Oil Water ◽  
Field Deployment

Abstract Although being widely used as an artificial lift method for heavy oil field developments, Electrical Submersible Pump (ESP) performance in high viscous applications is not fully understood. In order to improve knowledge of pump behavior under such conditions, Equinor has developed stage qualification tests as part of the technical requirements for deploying ESPs in Peregrino Field located offshore Brazil and has funded a series of research efforts to better design and operate the system more efficiently. Qualification tests were made mandatory for every stage type prior to field deployment in Peregrino. It is known that the affinity laws don´t hold true for high viscosity applications. Therefore, extensive qualification tests are required to provide actual stage performance in high viscous applications. Test results are used to optimize ESP system design for each well selecting the most efficient stage type considering specific well application challenges. In addition, the actual pump performance improves accuracy in production allocation algorithms. A better understanding of ESP behavior in viscous fluid application helps improving oil production and allows ESP operation with higher efficiency, increasing system run life. Shear forces inside ESP stages generate emulsion that compromises ESP performance. Lab tests in controlled environments have helped Equinor to gather valuable information about emulsion formation and evaluate ESP performance in conditions similar to field application. Equinor has funded studies to better understand two-phase flow (oil-water) which allowed visualization and investigation of oil drops dynamics inside the impeller. In addition, experimental procedures were proposed to investigate the effective viscosity of emulsion at pump discharge and the phase inversion hysteresis in the transition water-oil and oil-water emulsion. In addition to qualification tests and research performed to better understand system behavior, Equinor has developed and improved procedures to operate ESP systems in high viscous applications with emulsion production during 10 years of operation in Peregrino field. Such conditions also impose challenges to ESP system reliability. Over the years, Equinor has peformed failure analysis to enhance ESP system robustness which, combined with upper completion design, have improved system operation and reliability decreasing operating costs in Peregrino field.

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