Calcium Sulfate Scaling Risk and Inhibition for a Steamflood Project

SPE Journal ◽  
2016 ◽  
Vol 22 (03) ◽  
pp. 881-891 ◽  
Author(s):  
Fangfu Zhang ◽  
Charles J. Hinrichsen ◽  
Amy T. Kan ◽  
Wei Wang ◽  
Wei Wei ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Calcium Sulfate ◽  
Risk Model ◽  
Treatment Plan ◽  
Saturation Index ◽  
Middle Eastern ◽  
Oil Field ◽  
Water Composition ◽  
System Temperature

Summary Steamflooding is a widely used technique for heavy-oil recovery. Scale control during steamflooding, however, can be challenging because the high temperature of the steamflood can decompose thermally unstable inhibitors and/or lead to the precipitation of metal-inhibitor pseudoscale. In this paper, we present the analysis of the scaling risk and scale inhibition for a pilot steamflood project in a Middle Eastern oil field. The formation of this field is a dolomite formation interbedded with anhydrite (CaSO4) streaks. Anhydrite has been observed to be the predominant scale form. Anhydrite scale was presumably formed by the increased production-system temperature resulting from steamflooding and/or the mixing of steam condensate with connate water at equilibrium with calcium sulfate minerals at lower temperature and higher solubility. Anhydrite is inherently difficult to control because of its high solubility and the high-temperature (HT) conditions under which it forms. Compared with barite and calcite, only limited knowledge has been acquired for anhydrite control. To predict the scaling tendency and inhibitor need in different wells of this field with different supersaturation levels and temperatures, a scaling-risk model has been developed. To build such a model, detailed and revised laboratory procedures have been developed to study nucleation and precipitation kinetics of anhydrite at 125–175°C, different supersaturation, different water composition, and long reaction time. Predictions of this scaling-risk model suggest a saturation index (SI) of 0.8 as a critical SI for anhydrite control at >125°C. For example, when the SI is above 0.8, anhydrite will be difficult to control in the presence of threshold inhibitor. Model predictions were benchmarked with the water-chemistry data from a total of more than 20 wells from this field, and were found to be consistent with field observations of scale occurrence in different wells. With the recommended inhibitor concentrations, anhydrite scale has been controlled in this field, which provides validation that the proposed scaling-risk model is a powerful tool to optimize the scale-treatment plan for anhydrite.

scholarly journals Polymers for EOR Application in High Temperature and High Viscosity Oils: Rock–Fluid Behavior

Energies ◽  
2020 ◽  
Vol 13 (22) ◽  
pp. 5944
Author(s):  
Rubén H. Castro ◽  
Sebastián Llanos ◽  
Jenny Rodríguez ◽  
Henderson I. Quintero ◽  
Eduardo Manrique
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
High Viscosity ◽  
Oil Field ◽  
Heavy Oils ◽  
Displacement Efficiency ◽  
Reservoir Conditions ◽  
Oil Displacement Efficiency ◽  
Sulfonated Polyacrylamide ◽  
Total Dissolved Solid

Viscosity losses and high degradation factors have a drastic impact over hydrolyzed polyacrylamides (HPAM) currently injected, impacting the oil recovery negatively. Previous studies have demonstrated that biopolymers are promising candidates in EOR applications due to high thermochemical stability in harsh environments. However, the dynamic behavior of a biopolymer as scleroglucan through sandstone under specific conditions for a heavy oil field with low salinity and high temperature has not yet been reported. This work presents the rock–fluid evaluation of the scleroglucan (SG at 935 mgL−1) and sulfonated polyacrylamide (ATBS at 2500 mgL−1) to enhance oil recovery in high-temperature for heavy oils (212 °F and total dissolved solid of 3800 mgL−1) in synthetic (0.5 Darcy) and representative rock samples (from 2 to 5 Darcy) for a study case of a Colombian heavy oilfield. Dynamic evaluation at reservoir conditions presents a scenario with stable injectivity after 53.6 PV with a minimal pressure differential (less than 20 psi), inaccessible porous volume (IPV) of 18%, dynamic adsorption of 49 µg/g, and resistance and residual resistance factors of 6.17 and 2.84, respectively. In addition, higher oil displacement efficiency (up to 10%) was obtained with lower concentration (2.7 times) compared to a sulfonated polyacrylamide polymer.

scholarly journals Sulfidogenic Microbial Communities of the Uzen High-Temperature Oil Field in Kazakhstan

2021 ◽  
Vol 9 (9) ◽  
pp. 1818
Author(s):  
Diyana S. Sokolova ◽  
Ekaterina M. Semenova ◽  
Denis S. Grouzdev ◽  
Salimat K. Bidzhieva ◽  
Tamara L. Babich ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Oil Field ◽  
Injection Wells ◽  
Sulfate Reducing ◽  
Microbially Influenced Corrosion ◽  
Dsrab Gene ◽  
Fermentative Bacteria ◽  
Secondary Oil Recovery ◽  
Bottom Zone

Application of seawater for secondary oil recovery stimulates the development of sulfidogenic bacteria in the oil field leading to microbially influenced corrosion of steel equipment, oil souring, and environmental issues. The aim of this work was to investigate potential sulfide producers in the high-temperature Uzen oil field (Republic of Kazakhstan) exploited with seawater flooding and the possibility of suppressing growth of sulfidogens in both planktonic and biofilm forms. Approaches used in the study included 16S rRNA and dsrAB gene sequencing, scanning electron microscopy, and culture-based techniques. Thermophilic hydrogenotrophic methanogens of the genus Methanothermococcus (phylum Euryarchaeota) predominated in water from the zone not affected by seawater flooding. Methanogens were accompanied by fermentative bacteria of the genera Thermovirga, Defliviitoga, Geotoga, and Thermosipho (phylum Thermotogae), which are potential thiosulfate- or/and sulfur-reducers. In the sulfate- and sulfide-rich formation water, the share of Desulfonauticus sulfate-reducing bacteria (SRB) increased. Thermodesulforhabdus, Thermodesulfobacterium, Desulfotomaculum, Desulfovibrio, and Desulfoglaeba were also detected. Mesophilic denitrifying bacteria of the genera Marinobacter, Halomonas, and Pelobacter inhabited the near-bottom zone of injection wells. Nitrate did not suppress sulfidogenesis in mesophilic enrichments because denitrifiers reduced nitrate to dinitrogen; however, thermophilic denitrifiers produced nitrite, an inhibitor of SRB. Enrichments and a pure culture Desulfovibrio alaskensis Kaz19 formed biofilms highly resistant to biocides. Our results suggest that seawater injection and temperature of the environment determine the composition and functional activity of prokaryotes in the Uzen 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.

Geo-Thermo-Mechanical Modeling of Pre-Drilled Wellbores to Extract Geothermal Energy from Subsurface to Produce Cleaner Energy for United Arab Emirates

2021 ◽  
Author(s):  
Ubedullah Ansari ◽  
Najeeb Anjum Soomro ◽  
Farhan Ali Narejo ◽  
Shafquat Ali Baloch ◽  
Faiz Ali Talpur
Keyword(s):  
High Temperature ◽  
United Arab Emirates ◽  
Mechanical Model ◽  
Geothermal Energy ◽  
Oil And Gas ◽  
Middle Eastern ◽  
Clean Energy ◽  
Thermal Recovery ◽  
Abandoned Wells ◽  
Single Well

Abstract The middle eastern countries including United Arab Emirates (UAE) have enjoyed the energy production from hydrocarbon resource for a very long period. Indeed, now various countries in this region has shifted to alternative resources of power generation with cheaper and cleaner sources. Geothermal is the top of the list among those sources. Therefore, this study presents an ultimate model converting abandoned oil and gas wells into subsurface geothermal recovery points. Fundamentally, this study offers a geo-thermo-mechanical model of abandoned wellbore which can help in developing an optimistic geothermal energy not only from subsurface thermal reserve but also from abandoned casing and pipes installed in Wellbores. In this approach the source of heat is thermally active rock formations and the metallic pipes that are present in wellbores drilled through hot dry rocks. In the model the already drilled wells are incorporated as medium of heat flow in which water in injected and brought back to surface along with thermal impact. The results of this study revealed that, at the depth of 6000 m of high temperature wellbore the temperature is above 85°C and at this temperature the metallic casings further rise the reserve temperature thus the conversion of water into steam can be processed easily. Moreover, at high depths the stability of wellbore is also issue in high temperature formation, so mechanical model suggests that injection of water and conversion into steam in already cased wellbore can sustain up to 6 MPa stress at around 100C. Thus, the geo-thermo-mechanical model of wellbore will illustrate the possibility of converting water into steam and it will also reveal the average amount of heat that can be generated from a single well. henceforth, the thermal recovery from abandoned wells of UAE is best fit solution for clean energy. The abandoned wells are used as conduit to transport heat energy from subsurface by using water as transport medium, as water at surface temperature is injected in those wellbores and let thermal energy convert that water into steam. Later the steam is returned to surface and used as fuel in turbines or generators.

Application and Exploration of Early In-Situ Combustion Huff-and-Puff Technology in a Deep Undisturbed Reservoir with Extra Heavy Oil

2021 ◽  
pp. 1-13
Author(s):  
Wang Xiaoyan ◽  
Zhao Jian ◽  
Yin Qingguo ◽  
Cao Bao ◽  
Zhang Yang ◽  
...  
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Heavy Oil ◽  
Gas Injection ◽  
Thermal Recovery ◽  
Oil Field ◽  
Pilot Test ◽  
In Situ Combustion ◽  
Coiled Tubing

Summary Achieving effective results using conventional thermal recovery technology is challenging in the deep undisturbed reservoir with extra-heavy oil in the LKQ oil field. Therefore, in this study, a novel approach based on in-situ combustion huff-and-puff technology is proposed. Through physical and numerical simulations of the reservoir, the oil recovery mechanism and key injection and production parameters of early-stage ultraheavy oil were investigated, and a series of key engineering supporting technologies were developed that were confirmed to be feasible via a pilot test. The results revealed that the ultraheavy oil in the LKQ oil field could achieve oxidation combustion under a high ignition temperature of greater than 450°C, where in-situ cracking and upgrading could occur, leading to greatly decreased viscosity of ultraheavy oil and significantly improved mobility. Moreover, it could achieve higher extra-heavy-oil production combined with the energy supplement of flue gas injection. The reasonable cycles of in-situ combustion huff and puff were five cycles, with the first cycle of gas injection of 300 000 m3 and the gas injection volume per cycle increasing in turn. It was predicted that the incremental oil production of a single well would be 500 t in one cycle. In addition, the supporting technologies were developed, such as a coiled-tubing electric ignition system, an integrated temperature and pressure monitoring system in coiled tubing, anticorrosion cementing and completion technology with high-temperature and high-pressure thermal recovery, and anticorrosion injection-production integrated lifting technology. The proposed method was applied to a pilot test in the YS3 well in the LKQ oil field. The high-pressure ignition was achieved in the 2200-m-deep well using the coiled-tubing electric igniter. The maximum temperature tolerance of the integrated monitoring system in coiled tubing reached up to 1200°C, which provided the functions of distributed temperature and multipoint pressure measurement in the entire wellbore. The combination of 13Cr-P110 casing and titanium alloy tubing effectively reduced the high-temperature and high-pressure oxygen corrosion of the wellbore. The successful field test of the comprehensive supporting engineering technologies presents a new approach for effective production in deep extra-heavy-oil reservoirs.

ASP Flooding: A Solution for Chemical Enhanced Oil Recovery in High Temperature, Low Salinity Reservoir

2018 ◽  
Author(s):  
Cai Hongyan ◽  
Cheng Jie ◽  
Fan Jian ◽  
Luan Hexin ◽  
Wang Qing ◽  
...  
Keyword(s):  
High Temperature ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Low Salinity ◽  
Asp Flooding
Sign in / Sign up

Export Citation Format

Share Document