The New Deepwater Oil and Gas Province in Brazil: Flow Assurance and Artificial Lift: Innovations for Jubarte Heavy Oil

2007 ◽  
Author(s):  
Giovani Colodette ◽  
Carlos A.G. Pereira ◽  
Cézar A.M. Siqueira ◽  
Geraldo A.S.M. Ribeiro ◽  
Roberto Rodrigues ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Oil And Gas ◽  
Flow Assurance ◽  
Artificial Lift

Flow Assurance and Artificial Lift Innovations for Jubarte Heavy Oil in Brazil

2008 ◽  
Vol 3 (01) ◽  
pp. 1-8
Author(s):  
Giovani Colodette ◽  
Carlos Alberto Giacomim Pereira ◽  
Cezar Augusto M. Siqueira ◽  
Geraldo Afonso Spinelli Ribeiro ◽  
Roberto Rodrigues ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Flow Assurance ◽  
Artificial Lift

scholarly journals A comprehensive review of sucker rod pumps’ components, diagnostics, mathematical models, and common failures and mitigations

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Abdelaziz Khlaifat ◽  
M. Enamul Hossain ◽  
Hashim Nameer
Keyword(s):  
Mathematical Models ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Gas Industry ◽  
Holistic View ◽  
Comprehensive Review ◽  
Artificial Lift ◽  
Sucker Rod ◽  
Sucker Rod Pump

AbstractIn many oil reservoirs worldwide, the downhole pressure does not have the ability to lift the produced fluids to the surface. In order to produce these fluids, pumps are used to artificially lift the fluids; this method is referred to as artificial lift. More than seventy percent of all currently producing oil wells are being produced by artificial lift methods. One of the most applied artificial lift methods is sucker rod pump. Sucker rod pumps are considered a well-established technology in the oil and gas industry and thus are easy to apply, very common worldwide, and low in capital and operational costs. Many advancements in technology have been applied to improve sucker rod pumps performance, applicability range, and diagnostics. With these advancements, it is important to be able to constantly provide an updated review and guide to the utilization of the sucker rod pumps. This research provides an updated comprehensive review of sucker rod pumps components, diagnostics methods, mathematical models, and common failures experienced in the field and how to prevent and mitigate these failures. Based on the review conducted, a new classification of all the methods that can fall under the sucker rod pump technology based on newly introduced sucker rod pump methods in the industry has been introduced. Several field cases studies from wells worldwide are also discussed in this research to highlight some of the main features of sucker rod pumps. Finally, the advantages and limitations of sucker rod pumps are mentioned based on the updated review. The findings of this study can help increase the understanding of the different sucker rod pumps and provide a holistic view of the beam rod pump and its properties and modeling.

Perdido Startup: Flow Assurance and Subsea Artificial Lift Performance

2011 ◽  
Author(s):  
Howard Steven Littell ◽  
James Webster Jessup ◽  
W.W. Schoppa ◽  
M.R. Seay ◽  
T.D. Coulon
Keyword(s):  
Flow Assurance ◽  
Artificial Lift

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.

Compatibility Study of Condensate and Heavy Oil for Storage in an Iranian Reservoir

2021 ◽  
pp. 1-13
Author(s):  
K. Zobeidi ◽  
M. Ganjeh-Ghazvini ◽  
V. Hematfar
Keyword(s):  
Heavy Oil ◽  
Oil And Gas ◽  
Production Performance ◽  
Compatibility Study ◽  
Asphaltene Precipitation ◽  
High Concentration ◽  
Full Capacity ◽  
Potential Risks ◽  
Operational Criteria ◽  
Positive Effect

Summary During the years 2017–2020, when Iran faced restrictions on the sale of oil and gas condensate and due to the need for domestic consumption and gas sales commitments, it was inevitable to produce gas at full capacity. This coercion has led to significant production of gas condensates. Some of these condensates were sold, some were converted into products such as gasoline in domestic refineries, and some of these condensates needed to be stored, but the storage capacity was limited. For the purpose of underground condensate storage, a heavy oil reservoir was selected based on some technical and operational criteria. A feasibility study was conducted to evaluate the potential risks of condensate injection into the reservoir. The results of tests on asphaltene precipitation, as the most important risk, indicated no severe precipitation would occur even if high concentration of condensate mixed with the reservoir heavy oil. The recovery of condensate and the production performance of the reservoir were simulated in three different injection-production scenarios. The results showed a positive effect of condensate injection on production rate of the reservoir. Moreover, satisfactory volume of condensate could be recovered in a reasonable period of time.

Experimental Study and Modeling of Heating Effect in Electrical Submersible Pump Operating With Ultra-Heavy Oil

2018 ◽  
Author(s):  
Jorge Luiz Biazussi ◽  
Cristhian Porcel Estrada ◽  
William Monte Verde ◽  
Antonio Carlos Bannwart ◽  
Valdir Estevam ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Critical Factor ◽  
High Viscosity ◽  
Inlet Temperature ◽  
Outlet Temperature ◽  
Heating Effect ◽  
Submersible Pump ◽  
Oil Viscosity ◽  
Artificial Lift ◽  
Electrical Submersible Pump

A notable trend in the realm of oil production in harsh environments is the increasing use of Electrical Submersible Pump (ESP) systems. ESPs have even been used as an artificial-lift method for extracting high-viscosity oils in deep offshore fields. As a way of reducing workover costs, an ESP system may be installed at the well bottom or on the seabed. A critical factor, however, in deep-water production is the low temperature at the seabed. In fact, these low temperatures constitute the main source for many flow-assurance problems, such as the increase in friction losses due to high viscosity. Oil viscosity impacts pump performance, reducing the head and increasing the shaft power. This study investigates the influence of a temperature increase of ultra-heavy oil on ESP performance and the heating effect through a 10-stage ESP. Using several flow rates, tests are performed at four rotational speeds and with four viscosity levels. At each rotational speed curve, researchers keep constant the inlet temperature and viscosity. The study compares the resulting data with a simple heat model developed to estimate the oil outlet temperature as functions of ESP performance parameters. The experimental data is represented by a one-dimensional model that also simulates a 100-stage ESP. The simulations demonstrate that as the oil heat flows through the pump, the pump’s efficiency increases.

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.

Environmentally-Friendly Production and Recovery Processes for Heavy Oils

2021 ◽  
Author(s):  
Celal Hakan Canbaz ◽  
Cenk Temizel ◽  
Yildiray Palabiyik ◽  
Korhan Kor ◽  
Luky Hendrandingrat ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil And Gas ◽  
Steam Injection ◽  
Developed Countries ◽  
Green Energy ◽  
Heavy Oils ◽  
Recovery Processes ◽  
Injection Process ◽  
Environmental Footprints

Abstract Oil Industry is going green and there is no solid and comprehensive publication that outlines the use of green energies and methods in oil recovery. Thus, this paper is going to close that gap. As there are more environmental restrictions especially in developed countries, inclusion of green energy methods in petroleum recovery processes is very important for the future of these reserves. We will focus on extra/heavy oil as conventional oil is simpler to produce and doesn't need EOR processes that may come with environmental footprints. The objective of this study is to investigate and outline the ‘green’ production and recovery processes of heavy oil recovery in environmentally-sensitive locations where greenhouse gas emissions, type of energy used to extract oil and gas (e.g., generation of steam using natural gas vs solar), environmental impact of surface facilities, transportation of produced oil and gas and other associated materials/chemica ls required for recovery (e.g. solvents for steam injection process) are critical for the operations as well as economics.

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