scholarly journals Genome-Resolved Meta-Analysis of the Microbiome in Oil Reservoirs Worldwide

2021 ◽  
Vol 9 (9) ◽  
pp. 1812
Author(s):  
Kelly J. Hidalgo ◽  
Isabel N. Sierra-Garcia ◽  
German Zafra ◽  
Valéria M. de Oliveira
Keyword(s):  
Physicochemical Parameters ◽  
Meta Analysis ◽  
Water Injection ◽  
Petroleum Reservoirs ◽  
Oil Field ◽  
Oil Fields ◽  
Oil Reservoirs ◽  
Biogeochemical Transformations ◽  
Recovery Management ◽  
Key Microorganisms

Microorganisms inhabiting subsurface petroleum reservoirs are key players in biochemical transformations. The interactions of microbial communities in these environments are highly complex and still poorly understood. This work aimed to assess publicly available metagenomes from oil reservoirs and implement a robust pipeline of genome-resolved metagenomics to decipher metabolic and taxonomic profiles of petroleum reservoirs worldwide. Analysis of 301.2 Gb of metagenomic information derived from heavily flooded petroleum reservoirs in China and Alaska to non-flooded petroleum reservoirs in Brazil enabled us to reconstruct 148 metagenome-assembled genomes (MAGs) of high and medium quality. At the phylum level, 74% of MAGs belonged to bacteria and 26% to archaea. The profiles of these MAGs were related to the physicochemical parameters and recovery management applied. The analysis of the potential functional core in the reservoirs showed that the microbiota was specialized for each site, with 31.7% of the total KEGG orthologies annotated as functions (1690 genes) common to all oil fields, while 18% of the functions were site-specific, i.e., present only in one of the oil fields. The oil reservoirs with a lower level of intervention were the most similar to the potential functional core, while the oil fields with a long history of water injection had greater variation in functional profile. These results show how key microorganisms and their functions respond to the distinct physicochemical parameters and interventions of the oil field operations such as water injection and expand the knowledge of biogeochemical transformations in these ecosystems.

scholarly journals Microbiome Assessment of Global Oil Reservoirs Reveals Site-Specific Hydrocarbon Degradation Functional Profiles

2021 ◽  
Author(s):  
Kelly J. Hidalgo ◽  
Isabel N. Sierra-Garcia ◽  
German Zafra ◽  
Valéria M. de Oliveira
Keyword(s):  
Physicochemical Parameters ◽  
Water Injection ◽  
Petroleum Reservoirs ◽  
Oil Field ◽  
Oil Fields ◽  
Oil Reservoirs ◽  
Site Specific ◽  
Medium Quality ◽  
Recovery Management ◽  
Key Microorganisms

Microorganisms inhabiting subsurface petroleum reservoirs are key players in biochemical transformations. The interactions of microbial communities in these environments are highly complex and still poorly understood. This work aimed to assess publicly available metagenomes from oil reservoirs and implement a robust pipeline of genome-resolved metagenomics to deci-pher metabolic and taxonomic profiles of petroleum reservoirs worldwide. Analysis of 301,2 Gb of metagenomic information derived from heavily flooded petroleum reservoirs in China and Alaska to non-flooded petroleum reservoirs in Brazil enabled us to reconstruct 148 MAGs of high and medium quality. At the phylum level, 74% of MAGs belonged to bacteria and 26% to ar-chaea. The profiles of these MAGs were related to the physicochemical parameters and recovery management applied. The analysis of the potential functional core in the reservoirs showed that the microbiota was specialized for each site, with 31.7% of the total KEGG orthologies annotated as functions (1,690 genes) common to all oil fields, while 18% of the functions were site-specific, i.e., present only in one of the oil fields. The oil reservoirs with lower level of intervention were the most similar to the potential functional core, while the oil fields with longer history of water in-jection had greater variation in functional profile. These results show how key microorganisms and their functions respond to the distinct physicochemical parameters and interventions of the oil field operations such as water injection and expand the knowledge of biogeochemical trans-formations in these ecosystems.

DEVELOPMENT PLANNING FOR THE COSSACK AND WANAEA FIELDS

1994 ◽  
Vol 34 (1) ◽  
pp. 92
Author(s):  
G. B. Salter ◽  
W. P. Kerckhoff
Keyword(s):  
Cost Reduction ◽  
Water Injection ◽  
Development Planning ◽  
Oil Field ◽  
Oil Fields ◽  
Oil Reservoirs ◽  
Field Development ◽  
Oil Reserves ◽  
Oil Field Development ◽  
Significant Effort

Development of the Cossack and Wanaea oil fields is in progress with first oil scheduled for late 1995. Wanaea oil reserves are estimated in the order of 32 x 106m3 (200 MMstb) making this the largest oil field development currently underway in Australia.Development planning for these fields posed a unique set of challenges.Key subsurface uncertainties are the requirement for water injection (Wanaea only) and well numbers. Strategies for managing these uncertainties were studied and appropriate flexibility built-in to planned facilities.Alternative facility concepts including steel/concrete platforms and floating options were studied-the concept selected comprises subsea wells tied-back to production/storage/export facilities on an FPSO located over Wanaea.In view of the high proportion of costs associated with the subsea components, significant effort was focussed on flowline optimisation, simplification and cost reduction. These actions have led to potential major economic benefits.Gas utilisation options included reinjection into the oil reservoirs, export for re-injection into North Rankin or export to shore. The latter requires the installation of an LPG plant onshore and was selected as the simplest, safest and the most economically attractive method.

Challenges, Opportunities and Threats of Deep Bottoms-Up Water Injection in Heavy Oil Reservoir: Lessons Learnt from the G Field, South Oman

2021 ◽  
Author(s):  
Chaitanya Behera ◽  
Sandip Mahajan ◽  
Carlos Annia ◽  
Mahmood Harthi ◽  
Jane-Frances Obilaja ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Field Performance ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Light Oil ◽  
Alternative Water ◽  
Variable Water

Abstract This paper presents the results of a comprehensive study carried out to improve the understanding of deep bottom-up water injection, which enabled optimizing the recovery of a heavy oil field in South Oman. Understanding the variable water injection response and the scale of impact on oil recovery due to reservoir heterogeneity, operating reservoir pressure and liquid offtake management are the main challenges of deep bottoms-up water injection in heavy oil fields. The offtake and throughput management philosophy for heavy oil waterflood is not same as classical light oil. Due to unclear understanding of water injection response, sometimes the operators are tempted to implement alternative water injection trials leading to increase in the risk of losing reserves and unwarranted CAPEX sink. There are several examples of waterflood in heavy oil fields; however, very few examples of deep bottom water injection cases are available globally. The field G is one of the large heavy oil fields in South Oman; the oil viscosity varies between 250cp to 1500cp. The field came on-stream in 1989, but bottoms-up water-injection started in 2015, mainly to supplement the aquifer influx after 40% decline of reservoir pressure. After three years of water injection, the field liquid production was substantially lower than predicted, which implied risk on the incremental reserves. Alternative water injection concepts were tested by implementing multiple water injection trials apprehending the effectiveness of the bottoms-up water injection concept. A comprehensive integrated study including update of geocellular model, full field dynamic simulation, produced water re-injection (PWRI) model and conventional field performance analysis was undertaken for optimizing the field recovery. The Root Cause Analysis (RCA) revealed many reasons for suboptimal field performance including water injection management, productivity impairment due to near wellbore damage, well completion issues, and more importantly the variable water injection response in the field. The dynamic simulation study indicated negligible oil bank development due to frontal displacement and no water cut reversal as initial response to the water injection. Nevertheless, the significance of operating reservoir pressure, liquid offtake and throughput management impact on oil recovery cann't be precluded. The work concludes that the well reservoir management (WRM) strategy for heavy oil field is not same as the classical light oil waterflood. Nevertheless, the reservoir heterogeneity, oil column thickness and saturation history are also important influencing factors for variable water injection response in heavy oil field.

Characterization of sulfate-reducing bacteria isolated from oil-field waters

1996 ◽  
Vol 42 (3) ◽  
pp. 259-266 ◽  
Author(s):  
C. Tardy-Jacquenod ◽  
P. Caumette ◽  
R. Matheron ◽  
C. Lanau ◽  
O. Arnauld ◽  
...  
Keyword(s):  
Physicochemical Parameters ◽  
Sulfate Reducing Bacteria ◽  
Oil Field ◽  
Oil Fields ◽  
Gulf Of Guinea ◽  
Sulfate Reducing ◽  
The North ◽  
The North Sea ◽  
Reducing Bacteria

The occurrence and metabolic capacities of sulfate-reducing bacteria (SRB) were studied in 23 water samples taken from producing wells at 14 different sites. Oil fields in France, the North Sea, and the Gulf of Guinea were selected and classified according to physicochemical parameters (salinity ranging from 0.3 to 120 g∙L−1 and temperature between 29 and 85 °C). After the distribution of SRB within oil fields was studied, several strains of SRB were isolated and characterized metabolically. Twenty of the thirty-seven strains were not related to any known species. Most of the identified strains were members of the genera Desulfovibrio and Desulfotomaculum by molecular, morphological, and physiological properties.Key words: sulfate-reducing bacteria, oil-field ecology, metabolic identification, biodiversity.

scholarly journals Artificial lift management: Recommendations and suggestions of best practices

2011 ◽  
Vol 4 (3) ◽  
pp. 07-20
Author(s):  
Clemente-Marcelo Hirschfeldt
Keyword(s):  
Water Injection ◽  
Oil Field ◽  
Oil Fields ◽  
Service Companies ◽  
Artificial Lift ◽  
Effective Manner ◽  
Secondary Recovery ◽  
Evaluation And Monitoring ◽  
Management Recommendations ◽  
Field Production

Artificial lift systems (ALS) play an important role during the oil field production process. The selection, acquisition, installation, evaluation, monitoring and subsequent inspection of these systems involves different stakeholders, including the companies and different sectors therein. When you add factors such as field location, local culture and the experience of the companies in the area, understanding and analyzing each of the factors is critical not only to maximize the life of a specific ALS, but also to maximize and optimize field production in an efficient, effective manner. Another important factor to consider is the dynamic of developing new oil fields or those affected by different EOR technologies, such as secondary recovery by water injection, where field requirements and conditions change on a continuous basis. This paper presents concepts and recommendations regarding the management of ALS during the productive life of an oil field, contemplating the criteria of selection, acquisition, installation, evaluation and monitoring, as well as the subsequent inspection thereof. The issues analyzed herein also involve concepts related to operating as well as service companies and sectors involved in acquisition, evaluation and monitoring, among others. It also mentions definitions of the roles, functions and competencies required to live up to the challenges posed by these systems.

scholarly journals Water Injection for Oil Recovery in Mishrif Formation for Amarah Oil Field

2020 ◽  
Vol 21 (1) ◽  
pp. 39-44
Author(s):  
Ayat Ahmed Jassim ◽  
Abdul Aali Al-dabaj ◽  
Aqeel S. AL-Adili
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Petroleum Reservoirs ◽  
Oil Production ◽  
Oil Field ◽  
Reservoir Pressure ◽  
Vertical Wells ◽  
First Case ◽  
New Ideas

The water injection of the most important technologies to increase oil production from petroleum reservoirs. In this research, we developed a model for oil tank using the software RUBIS for reservoir simulation. This model was used to make comparison in the production of oil and the reservoir pressure for two case studies where the water was not injected in the first case study but adding new vertical wells while, later, it was injected in the second case study. It represents the results of this work that if the water is not injected, the reservoir model that has been upgraded can produce only 2.9% of the original oil in the tank. This case study also represents a drop in reservoir pressure, which was not enough to support oil production. Thus, the implementation of water injection in the second case study of the average reservoir pressure may support, which led to an increase in oil production by up to 5.5% of the original oil in the tank. so that, the use of water injection is a useful way to increase oil production. Therefore, many of the issues related to this subject valuable of study where the development of new ideas and techniques.

Evaluation of the Low Tension Flood Process for High-Salinity Reservoirs-Laboratory Investigation Under Reservoir Conditions

1982 ◽  
Vol 22 (06) ◽  
pp. 831-846 ◽  
Author(s):  
Hani Murtada ◽  
Claus Marx
Keyword(s):  
Oil Recovery ◽  
High Salinity ◽  
Oil Field ◽  
Oil Fields ◽  
Oil Reservoirs ◽  
Residual Oil ◽  
Total Recovery ◽  
Northwest Germany ◽  
Reservoir Conditions ◽  
Low Tension

Abstract In northwest Germany, oil reservoirs are characterized by high-salinity brines with up to 23% TDS. For such salinity conditions, fatty alcohol derivatives with 4.5 ethene oxide (EO) units were found to lower the interfacial tension (IFT) drastically and to mobilize residual oil almost completely. Intensive flood experiments under reservoir conditions with the use of sand packs 2 m in length allowed optimizing the low-tension process for an oil field that was considered a possible candidate. A combination of surfactant slug followed by a tailored mobility buffer showed best results in terms of additional oil recovery and process duration. A preflush of low-concentration aqueous polymer solution brought a decisive further increase in additional oil recovery. Results obtained for the slug process indicated that variables such as IFT, surfactant concentration, flooding velocity, and pressure gradient influence the low-tension process in a combined manner. Oil produced in the oil bank showed alteration in properties, compared with the oil used to saturate the pore space. Introduction This paper summarizes the concept, development, and results of a low-tension flood process for the high-salinity reservoirs in northwestern Germany with the use of surfactants. The objectives were:to design an appropriate surfactant flooding process for mobilizing residual oil in reservoirs in northwest Germany such that a pronounced lowering of IFT between the oil and aqueous phase is achieved,to conduct investigations on the main parameters influencing the process, andto perform practically oriented laboratory flooding experiments for optimizing the process for real oil reservoirs. Most oil reservoirs in the Federal Republic of Germany (FRG) are characterized by extremely unfavorable conditions of salinity. Besides the high sodium chloride content, the reservoir brines have remarkably high concentrations of calcium and magnesium salts. Typical values are 50 to 250 g/dm3 NaCl and 4 to 20 g/dm3 Ca++. No surfactants suitable for such saline environments were known before 1975. Reserve Situation in the FRG Because it is not likely that new oil fields will be discovered in the FRG, the domestic oil industry is striving to develop new technologies for enhancing oil recovery after termination of primary and secondary production phases. For highly saline conditions such as those prevailing in northwestern German oil fields, the development of effective surfactants was necessary. In addition to being soluble in original reservoir water, these surfactants must lower the IFT drastically and must completely mobilize the residual oil remaining in the porous medium after previous water flooding. A modification of original reservoir brines by eventual conditioning or by preflushing in-situ formation water was not intended. Such measures had proved effective in the laboratory but not in the field. Oil production statistics from 1978 show that about 22% OOIP in the FRG already has been produced. According to these statistics, it is expected that a further 10% OOIP will be produced with conventional recovery processes (e.g., waterflooding). Of the OIP remaining (target for tertiary recovery, about 68 % OOIP), approximately 15% should be recoverable by EOR processes currently known or to be developed. Thus, the total recovery would be increased to 47%. The remaining 54% will not be recoverable, according to current estimates. SPEJ P. 831^

Austin Chalk and Buda Limestone (Cretaceous) Petroleum Reservoirs in Caldwell County, Texas—A Case History

1986 ◽  
Vol 4 (5) ◽  
pp. 377-389
Author(s):  
William C. Dawson
Keyword(s):  
Case History ◽  
Petroleum Reservoirs ◽  
South Texas ◽  
Oil Fields ◽  
Oil Reservoirs ◽  
The Past ◽  
Austin Chalk ◽  
Fractured Carbonate ◽  
Completion Problems ◽  
Commercial Oil

The Austin Chalk and Buda Limestone are commercial oil reservoirs along a 250-mile trend extending from Dimmit to Burleson counties, Texas. This south Texas Cretaceous hydrocarbon trend has been the focus during the past six decades of several ‘drilling booms’ which have delimited numerous large oil fields in fractured carbonate reservoirs adjacent to major faults. Data from wells drilled near two newly mapped faults in Caldwell County, Texas, indicate that, despite its maturely drilled status, the Austin-Buda trend has some future exploratory potential. Representative well histories reveal drilling and completion problems and economic risks that characterize the Austin-Buda trend.

scholarly journals Injection-production optimization of carbonate reservoir based on an inter-well connectivity model

2021 ◽  
pp. 014459872199465
Author(s):  
Yuhui Zhou ◽  
Sheng Lei ◽  
Xuebiao Du ◽  
Shichang Ju ◽  
Wei Li
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Field Application ◽  
Carbonate Reservoir ◽  
Production Optimization ◽  
Oil Field ◽  
Carbonate Reservoirs ◽  
Utilization Rate ◽  
Production Volume ◽  
Connectivity Model

Carbonate reservoirs are highly heterogeneous. During waterflooding stage, the channeling phenomenon of displacing fluid in high-permeability layers easily leads to early water breakthrough and high water-cut with low recovery rate. To quantitatively characterize the inter-well connectivity parameters (including conductivity and connected volume), we developed an inter-well connectivity model based on the principle of inter-well connectivity and the geological data and development performance of carbonate reservoirs. Thus, the planar water injection allocation factors and water injection utilization rate of different layers can be obtained. In addition, when the proposed model is integrated with automatic history matching method and production optimization algorithm, the real-time oil and water production can be optimized and predicted. Field application demonstrates that adjusting injection parameters based on the model outputs results in a 1.5% increase in annual oil production, which offers significant guidance for the efficient development of similar oil reservoirs. In this study, the connectivity method was applied to multi-layer real reservoirs for the first time, and the injection and production volume of injection-production wells were repeatedly updated based on multiple iterations of water injection efficiency. The correctness of the method was verified by conceptual calculations and then applied to real reservoirs. So that the oil field can increase production in a short time, and has good application value.

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