Effecting a Pneumatic Operated Assembly, for an Improved Oil Recovery IOR, in Onshore Wells

2021 ◽  
Author(s):  
Abednego Ishaya, Wakili
Keyword(s):  
Control Systems ◽  
Production Rate ◽  
Oil Recovery ◽  
Pressure Control ◽  
Compressed Air ◽  
Improved Oil Recovery ◽  
Secondary Recovery ◽  
Pressure Development ◽  
Hydrocarbon Formation ◽  
Original Oil In Place

Abstract As hydrocarbon formation continues, owing to its natural sourcing, technologies have continually emerged on how these hydrocarbons can be effectively produced at a commercial benchmark. Asides its natural drive system, the enhanced oil recovery methods have been one key approach that has been effected towards increasing hydrocarbon's production rate, from its reservoirs. The natural reservoir energy has allowed for about 10% production of original oil in place. And, extending a field's productive life by employing the secondary recovery has further improved production to 20 to 40%, with EOR amounting to about 30 to 60% production. This however, would tell of the impending need towards further developments on increasing upon this production rate. Hence, the approach on using a pneumatic operated assembly with considerations made on onshore wells. This paper seeks to depict a focal on "Pneumatic IOR (Improved Oil Recovery)" as a method to be effected for onshore wells towards improving its productivity. The pneumatic system uses compressed air, contained in a cylinder - through specialized tubing, alongside pressure control systems, that helps regulate the flow and amount of the compressed air; to propel a metallic bar that will act on the reservoir surface. A force of impact, which will induce vibrations inwards, is generated. The mechanical motion of the metal bars for which this compressed air acts upon will provide the travel force, which when it acts on the reservoir surface of interest, will induce geologic stresses. This stresses and vibrations are important constituents in increasing pressure, downhole. Thereby, enabling fluid flow upwards through the wellbore to the surface. And, this will proffer the necessary physics, needed for pressure development downhole, which will be of importance in improving Oil Recovery.

Advances in Midland Basin Expand Boundaries of CO2 EOR in Marginal Pay Areas

2021 ◽  
Vol 73 (06) ◽  
pp. 65-66
Author(s):  
Judy Feder
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Improved Oil Recovery ◽  
Midland Basin ◽  
The North ◽  
Production Wells ◽  
Original Oil In Place ◽  
Carbon Dioxide Co2

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200460, “A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance,” by John Kalteyer, SPE, Kinder Morgan, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field’s future. Field Overview and Development History The first six pages of the paper discuss the field’s location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has sur-passed 7 TCF and yielded cumulative EOR of over 180 million bbl. The reservoir is a primarily limestone reef complex containing an estimated original oil in place (OOIP) of just under 3 billion bbl. The reservoir ranges from 200 ft gross thickness in the south to 900 ft in the north, where the limestone matrix averages 8% porosity and 20-md permeability. The Canyon Reef structure is divided into four major intervals, of which the Upper Canyon zone provides the highest-quality pay. The field was discovered in 1948 at a pressure of 3,122 psi. By late 1950, 1,600 production wells had been drilled and the reservoir pressure plummeted, settling as low as 1,700 psi. Waterflooding begun in 1954 enabled the field to continue producing for nearly 20 years, at which time the operators deter-mined that another recovery mechanism would be needed to maximize recovery and reach additional areas of the field. The complete paper discusses various CO2 injection programs that were developed and applied—including a true tertiary response from a miscible CO2 flood in 1981—along with their outcomes. Acquisition and CO2-Injection Redevelopment In June 2000 Kinder Morgan acquired the SACROC Unit and took over as operator. Approximately 6.7 billion bbl of water and 1.3 TCF of CO2 had been injected across the unit to that date, but the daily oil rate of 8,700 B/D was approaching the field’s economic limit. An estimated 40% of the OOIP had been produced through the combination of recovery methods that each previous operator had used. Expanding on the conclusions of its immediate predecessor, the operator initiated large-scale CO2-flood redevelopment in a selection of project areas. These redevelopments were based on several key distinctions differentiating them from previous injection operations.

scholarly journals Chemical-Enhanced Oil Recovery Using N,N-Dimethylcyclohexylamine on a Colombian Crude Oil

2019 ◽  
Vol 2019 ◽  
pp. 1-10 ◽  
Author(s):  
Diego R. Merchan-Arenas ◽  
Cindy Carolina Villabona-Delgado
Keyword(s):  
Crude Oil ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Tertiary Amine ◽  
Recovery Process ◽  
Rock System ◽  
Recovery Yield ◽  
Oil Reserves ◽  
Secondary Recovery ◽  
Original Oil In Place

Oil recovery was improved using the tertiary amine, N,N-dimethylcyclohexylamine (DMCHA), a powerful and promissory switchable solvent, in simulated conditions similar to the Colombian crude oil reserves. Firstly, the Colombian crude oil (CCO) and the soil were characterized completely. Afterwards, an aged crude-rock system was obtained to use DMCHA that gave an oil crude extraction of 80% in our preliminary studies. Thus, a sand-pack column (soil-kaolin, 95 : 5) frame saturated with CCO was used to simulate the conditions, in which DMCHA could recover the oil. After the secondary recovery process, 15.4–33.8% of original oil in place (OOIP) is obtained. Following the injection of DMCHA, the recovery yield rose to 87–97% of OOIP. Finally, 54–60% of DMCHA was recovered and reinjected without affecting its potential in the simulated conditions.

scholarly journals Microbial Enhanced Oil Recovery (MEOR): Alternatif Peningkatan Produksi Migas di Indonesia

2020 ◽  
Vol 2 (2) ◽  
pp. 01-08
Author(s):  
Desy Hikmatul Siami ◽  
◽  
Novi Hery Yono ◽  
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Oil Production ◽  
Oil Viscosity ◽  
Improved Oil Recovery ◽  
Oil Saturation ◽  
Reservoir Rocks ◽  
Secondary Recovery ◽  
Salinity Water ◽  
Water Cut

The need for petroleum is increasing along with the development of the industry, while the production results from the process of recovering oil from the reservoir by using primary recovery and secondary recovery are still very low so that it takes an advanced stage, namely tertiary recovery or, known as EOR. EOR is a method that produces oil production above 50%. EOR is an effort to increase oil production, so it is included in the IOR (Improved Oil Recovery) section. EOR consists of various applications, ranging from water injection, chemical injection, gases injection to microbiology injection. The stages in the injection of water and gas still leave oil trapped in the rocks in the reservoir. MEOR is one method that can be used to bring oil trapped in reservoir rocks to the surface. The effectiveness of the MEOR method is measured based on several parameters that is formation temperature, oil viscosity, permeability, saltwater salinity, water cut, API gravity crude oil, pH, pressure, residual oil saturation, porosity depth and bacterial content in the reservoir.

Influence of chemical composition of mixing water on the gelation of inorganic polymer technology for improved oil recovery

2017 ◽  
Vol 3 (3) ◽  
pp. 33-38 ◽  
Author(s):  
А.V. Аntuseva ◽  
Е.F. Kudina ◽  
G.G. Pechersky ◽  
Y.R. Kuskildina ◽  
А.V., Melgui ◽  
...  
Keyword(s):  
Chemical Composition ◽  
Oil Recovery ◽  
Inorganic Polymer ◽  
Improved Oil Recovery ◽  
Mixing Water

Technologies for improved oil recovery by deep cleaning of the bottom-hole zone of wells with RBS-3 and DGK-2 reagents

2020 ◽  
Vol 7 ◽  
pp. 116-119
Author(s):  
R.N. Fakhretdinov ◽  
◽  
D.F. Selimov ◽  
A.A. Fatkullin ◽  
S.A. Tastemirov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Improved Oil Recovery ◽  
Bottom Hole

scholarly journals Isolation and characterization study towards microbial improved oil recovery applications

2020 ◽  
Author(s):  
Hala Abdulkareem Rasheed ◽  
Mohammed Abdulmunem Abdulhameed ◽  
Rasha Al Sahlanee
Keyword(s):  
Oil Recovery ◽  
Improved Oil Recovery ◽  
Isolation And Characterization ◽  
Characterization Study

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

2014 ◽  
Vol 17 (03) ◽  
pp. 304-313 ◽  
Author(s):  
A.M.. M. Shehata ◽  
M.B.. B. Alotaibi ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Oil Recovery ◽  
Sudden Change ◽  
Oil Production ◽  
Deionized Water ◽  
Production Performance ◽  
Shallow Aquifer ◽  
Secondary Recovery ◽  
Tertiary Recovery ◽  
The Impact ◽  
Indiana Limestone

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

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