Overcoming Artificial Lift Failures in Polymer Flooding Oil Field in the South of Oman

2018 ◽  
Author(s):  
Nada Al-Sidairi ◽  
Mahmoud Osman ◽  
Nasir Oritola ◽  
Farsi Ahmed ◽  
Khalid Zuhaimi ◽  
...  
Keyword(s):  
Polymer Flooding ◽  
Oil Field ◽  
The South ◽  
Artificial Lift

Application of Polymer Flooding in the Revitalization of a Mature Heavy Oil Field

2021 ◽  
pp. 108695
Author(s):  
L.F. Lamas ◽  
V.E. Botechia ◽  
D.J. Schiozer ◽  
M.L. Rocha ◽  
M. Delshad
Keyword(s):  
Heavy Oil ◽  
Polymer Flooding ◽  
Oil Field

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.

An Alkaline Bio-Surfactant Polymer Flooding Pilots in Daqing Oil Field

1999 ◽  
Author(s):  
Wang Demin ◽  
Cheng Jiecheng ◽  
Li Qun ◽  
Li Lizhong ◽  
Zhao Changjiu
Keyword(s):  
Polymer Flooding ◽  
Oil Field ◽  
Daqing Oil Field

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

scholarly journals The Mesozoic of the South Caspian oil and gas province, Southwestern Turkmenistan – prospects for gas and oil exploration

2021 ◽  
pp. 102-133
Author(s):  
V.N. Melikhov ◽  
N.A. Krylov ◽  
I.V. Shevchenko ◽  
V.L. Shuster
Keyword(s):  
Oil And Gas ◽  
High Efficiency ◽  
State Of The Art ◽  
Oil Field ◽  
Seismic Exploration ◽  
Oil Exploration ◽  
The South ◽  
Analytical Review ◽  
Drilling Operations ◽  
Low Efficiency

Regarding the South Caspian oil and gas province, it is concluded that the Pliocene productivity prevails in the western part of the province, and that the gas and oil prospects of the eastern land side in the Mesozoic are prioritized. A retrospective analytical review of geological and geophysical data and publications on the Mesozoic of Southwestern Turkmenistan was carried out, which showed the low efficiency of the performed seismic and drilling operations in the exploration and evaluation of very complex Mesozoic objects. A massive resumption of state-of-the-art seismic exploration and appraisal drilling in priority areas and facilities performed by leading Russian companies is proposed. For some areas, a new, increased estimate of the projected gas resources is given. An example of modern high-efficiency additional exploration of the East Cheleken, a small Pliocene gas and oil field, which turned this field into a large one in terms of reserves, is given.

The Mechanism of PCP Wells' Tubing and Rod Wear Issue in Polymer Flooding in Daqing Oil Field

2008 ◽  
Author(s):  
He Liu ◽  
Pei Xiaohan ◽  
Peng Baiqi ◽  
Hou Yu ◽  
Wang Yumei ◽  
...  
Keyword(s):  
Polymer Flooding ◽  
Oil Field ◽  
Daqing Oil Field

Review of Practical Experience by Polymer Flooding at Daqing

2009 ◽  
Vol 12 (03) ◽  
pp. 470-476 ◽  
Author(s):  
Dongmei Wang ◽  
Huanzhong Dong ◽  
Changsen Lv ◽  
Xiaofei Fu ◽  
Jun Nie
Keyword(s):  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Molecular Weights ◽  
Well Spacing ◽  
Polymer Flood ◽  
Daqing Oil Field ◽  
Water Cut

Summary This paper describes successful practices applied during polymer flooding at Daqing that will be of considerable value to future chemical floods, both in China and elsewhere. On the basis of laboratory findings, new concepts have been developed that expand conventional ideas concerning favorable conditions for mobility improvement by polymer flooding. Particular advances integrate reservoir-engineering approaches and technology that is basic for successful application of polymer flooding. These include the following:Proper consideration must be given to the permeability contrast among the oil zones and to interwell continuity, involving the optimum combination of oil strata during flooding and well-pattern design, respectively;Higher polymer molecular weights, a broader range of polymer molecular weights, and higher polymer concentrations are desirable in the injected slugs;The entire polymer-flooding process should be characterized in five stages--with its dynamic behavior distinguished by water-cut changes; -Additional techniques should be considered, such as dynamic monitoring using well logging, well testing, and tracers; effective techniques are also needed for surface mixing, injection facilities, oil production, and produced-water treatment; andContinuous innovation must be a priority during polymer flooding. Introduction China's Daqing oil field entered its ultrahigh-water-cut period after 30 years of exploitation. Just before large-scale polymer-flooding application, the average water-cut was more than 90%. The Daqing oil-field is a large river-delta/lacustrine facies, multilayered with complex geologic conditions and heterogeneous sandstone in an inland basin. After 30 years of waterflooding, many channels and high-permeability streaks were identified in this oil field (Wang and Qian 2002). Laboratory research began in the 1960s, investigating the potential of enhanced-oil-recovery (EOR) processes in the Daqing oil field. After a single-injector polymer flood with a small well spacing of 75 m in 1972, polymer flooding was set on pilot test. During the late 1980s, a pilot project in central Daqing was expanded to a multiwell pattern with larger well spacing. Favorable results from these tests--along with extensive research and engineering from the mid-1980s through the 1990s--confirmed that polymer flooding was the preferred method to improve areal- and vertical-sweep efficiency at Daqing and to provide mobility control (Wang et al. 2002, Wang and Liu 2004). Consequently, the world's largest polymer flood was implemented at Daqing, beginning in 1996. By 2007, 22.3% of total production from the Daqing oil field was attributed to polymer flooding. Polymer flooding boosted the ultimate recovery for the field to more than 50% of original oil in place (OOIP)--10 to 12% OOIP more than from waterflooding. At the end of 2007, oil production from polymer flooding at the Daqing oil field was more than 10 million tons (73 million bbl) per year (sustained for 6 years). The focus of this paper is on polymer flooding, in which sweep efficiency is improved by reducing the water/oil mobility ratio in the reservoir. This paper is not concerned with the use of chemical gel treatments, which attempt to block water flow through fractures and high-permeability strata. Applications of chemical gel treatments in China have been covered elsewhere (Liu et al. 2006).

scholarly journals Numerical Well Test Analysis for Polymer Flooding considering the Non-Newtonian Behavior

2015 ◽  
Vol 2015 ◽  
pp. 1-10
Author(s):  
Jia Zhichun ◽  
Li Daolun ◽  
Yang Jinghai ◽  
Xue Zhenggang ◽  
Lu Detang
Keyword(s):  
Transient Response ◽  
Polymer Concentration ◽  
Shear Thinning ◽  
Polymer Flooding ◽  
Oil Field ◽  
Well Test ◽  
Well Test Analysis ◽  
Test Analysis ◽  
Pressure Transient ◽  
Thinning Effect

Well test analysis for polymer flooding is different from traditional well test analysis because of the non-Newtonian properties of underground flow and other mechanisms involved in polymer flooding. Few of the present works have proposed a numerical approach of pressure transient analysis which fully considers the non-Newtonian effect of real polymer solution and interprets the polymer rheology from details of pressure transient response. In this study, a two-phase four-component fully implicit numerical model incorporating shear thinning effect for polymer flooding based on PEBI (Perpendicular Bisection) grid is developed to study transient pressure responses in polymer flooding reservoirs. Parametric studies are conducted to quantify the effect of shear thinning and polymer concentration on the pressure transient response. Results show that shear thinning effect leads to obvious and characteristic nonsmoothness on pressure derivative curves, and the oscillation amplitude of the shear-thinning-induced nonsmoothness is related to the viscosity change decided by shear thinning effect and polymer concentration. Practical applications are carried out with shut-in data obtained in Daqing oil field, which validates our findings. The proposed method and the findings in this paper show significant importance for well test analysis for polymer flooding and the determination of the polymer in situ rheology.

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.

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