Unlocking Heavy Oil Potential From Shallow Reservoirs: Successful Cold Flow Testing of Heavy Oil Exploration Wells with PCP Artificial Lift System

2015 ◽  
Author(s):  
Abdullah Al-Ibrahim ◽  
Haifa Al-Bader ◽  
Abdul Razzaq ◽  
S. Packirisamy ◽  
D. Vidya Sagar ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Oil Exploration ◽  
Cold Flow ◽  
Artificial Lift ◽  
Shallow Reservoirs

Geoelectrical resistivity imaging of shallow oil sands in the Eastern Dahomey Basin (SW Nigeria): Implication for heavy oil exploration and production

2021 ◽  
Vol 176 ◽  
pp. 104122
Author(s):  
Ovie Emmanuel Eruteya ◽  
Muhedeen Ajibola Lawal ◽  
Kamaldeen Olakunle Omosanya ◽  
Adeoye Oshomoji ◽  
Usman Kaigama ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Oil Sands ◽  
Oil Exploration ◽  
Resistivity Imaging ◽  
Dahomey Basin ◽  
Exploration And Production ◽  
Geoelectrical Resistivity

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.

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.

Analysis of the Flow Velocity of Heavy Oil Reservoir Flooding Vent Complex Process

2014 ◽  
Vol 1015 ◽  
pp. 308-311
Author(s):  
Jia Mei Geng
Keyword(s):  
Heavy Oil ◽  
Thermal Recovery ◽  
Oil Reservoir ◽  
Oil Exploration ◽  
Seepage Velocity ◽  
Reservoir Development ◽  
Complex Process ◽  
World Demand ◽  
Heavy Oil Reservoir ◽  
The Impact

With the deepening of the degree of oil exploration and development, as well as the rapid growth of world demand for oil, heavy oil reservoir development is becoming increasingly important in the position in oil exploration. For reserves a great deal of ultra heavy oil reservoir at present, conventional thermal recovery technology is difficult to obtain a good development effect. In this study we use computational fluid dynamics software ANYSY CFX to analyze the impact of horizontal and vertical pressure gradient on the seepage velocity difference..

Progressing-Cavity-Pump Configuration Addresses Operational Challenges

2021 ◽  
Vol 73 (03) ◽  
pp. 42-43
Author(s):  
Chris Carpenter
Keyword(s):  
Heavy Oil ◽  
Oil Production ◽  
End Users ◽  
Active Section ◽  
Artificial Lift ◽  
Design And Manufacturing ◽  
Performance Decline ◽  
A Performance

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201130, “Novel Progressing-Cavity-Pump Configurations Address Operational Challenges,” by Lonnie Dunn, SPE, Ryan Rowan, and Abhishek Prakash, Lifting Solution, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition-Americas, 10-12 November. The paper has not been peer reviewed. While downhole progressing-cavity-pump (PCP) designs provide options for end users, the numerous products available, combined with a lack of industry standardization, can make selection and application challenging. The complete paper provides an overview of the development of a PCP concept and implementation, which is not included in this synopsis, and then summarizes two novel PCP configurations deployed to address specific operational challenges. Design and Manufacturing, Configuration 1 A novel PCP configuration was developed from phased design trials and experience in cold heavy-oil production with sand (CHOPS) wells. This configuration uses a modified rotor to create alternating sections of contact and noncontact within a conventional stator (Fig. 1). The rotor is landed in the stator and operated until there is a performance decline. Then, the rotor is repositioned to move the active section of the rotor into the areas of the stator where there originally was no contact and, as such, normally no associated damage. Keeping the length of the alternating sections short simplifies the surface rotor positioning process, allowing it to be performed riglessly. The main benefit of this is that, rather than having to pull the rod string and run a different rotor, the same rotor is used and repositioned through lifting of the rod string at surface.

Artificial Lift Practice For Heavy Oil Production With Sand Control

2010 ◽  
Author(s):  
Alexander Petrov ◽  
Alexander Mikhaylov ◽  
Konstantin Litvinenko
Keyword(s):  
Heavy Oil ◽  
Oil Production ◽  
Artificial Lift ◽  
Sand Control
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