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.

Artificial Lift Management: Recommendations for Unconventional Oilfields

2012 ◽  
Author(s):  
Clemente Marcelo Hirschfeldt ◽  
Fernando Flores Avila ◽  
Jaime Granados Cáliz
Keyword(s):  
Latin American ◽  
Evaluation Criteria ◽  
Monitoring And Evaluation ◽  
Production Costs ◽  
Oil Fields ◽  
Service Companies ◽  
Whole Process ◽  
Artificial Lift ◽  
Latin American Region ◽  
Management Recommendations

This paper presents concepts and recommendations regarding Artificial Lift Systems (ALS’s) management during productive life of oil fields, envisioning: selection, acquisition, installation, monitoring and evaluation criteria, as well as subsequent inspection thereof, and highlighting the more important that applies particularly to unconventional oil fields. Issues analyzed herein involve definitions of roles, functions and competencies related to operator as well as service companies and sectors involved or required to live up to the challenges posed by these systems. Two scenarios that represent Latin American region real cases are presented and illustrated with the analysis of these ALS’s management topics; one of them, the oldest productive basin in Argentina, as an example of conventional oilfields with experience in Artificial Lift Management and the other, an unconventional field recently re-activated with an accelerated development pace, being exploited in Mexico. Conclusions are presented in terms of that ALS’s Integral management should be taken with strategic and integrated vision, in accordance with current level of development, future plans, and complexity of the field; not only focused on maximum oil production, but also on optimizing production costs; and contemplate all parts commitment that add value to the whole process.

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.

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.

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.

scholarly journals Implementation of Rock Typing on Waterflooding Process During Secondary Recovery in Oil Reservoirs: A Case Study, El Morgan Oil Field, Gulf of Suez, Egypt

2021 ◽  
Author(s):  
Ahmed E. Radwan ◽  
Bassem S. Nabawy ◽  
Ahmed A. Kassem ◽  
Walid S. Hussein
Keyword(s):  
Water Injection ◽  
Oil Field ◽  
Production Data ◽  
Reservoir Quality ◽  
Gulf Of Suez ◽  
Hydraulic Flow ◽  
Flow Units ◽  
Rock Typing ◽  
Secondary Recovery ◽  
Hydraulic Flow Units

AbstractWaterflooding is one of the most common secondary recovery methods in the oil and gas industry. Globally, this process sometimes suffers a technical failure and inefficiency. Therefore, a better understanding of geology, reservoir characteristics, rock typing and discrimination, hydraulic flow units, and production data is essential to analyze reasons and mechanisms of water injection failure in the injection wells. Water injection failure was reported in the Middle Miocene Hammam Faraun reservoir at El Morgan oil field in the Gulf of Suez, where two wells have been selected as injector’s wells. In the first well (A1), the efficiency of injection was not good, whereas in the other analog A2 well good efficiency was assigned. Therefore, it is required to assess the injection loss in the low efficiency well, where all aspects of the geological, reservoir and production data of the studied wells were integrated to get a complete vision for the reasons of injection failure. The available data include core analysis data (vertical and horizontal permeabilities, helium porosity, bulk density, and water and oil saturations), petrographical studies injection and reservoir water chemistry, reservoir geology, production, and injection history. The quality of the data was examined and a set of reliable X–Y plots between the available data were introduced and the reservoir quality in both wells was estimated using reservoir quality index, normalized porosity index, and flow zone indicator. Integration and processing of the core and reservoir engineering data indicate that heterogeneity of the studied sequence was the main reason for the waterflooding inefficiency at the El Morgan A1 well. The best reservoir quality was assigned to the topmost part of the reservoir, which caused disturbance of the flow regime of reservoir fluids. Therefore, it is clearly indicated that rock typing and inadequate injection perforation strategy that has not been aligned with accurate hydraulic flow units are the key control parameters in the waterflooding efficiency.

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.

Integrated laboratory studies when optimizing surfactant-polymer formulations for oil deposits in Western Siberia

2021 ◽  
pp. 107-118
Author(s):  
E. A. Sidorovskaya ◽  
D. S. Adakhovskij ◽  
N. Yu. Tret'yakov ◽  
L. P. Panicheva ◽  
S. S. Volkova ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Western Siberia ◽  
Polymer System ◽  
Aqueous Solubility ◽  
Oil Field ◽  
Oil Fields ◽  
Laboratory Studies ◽  
Secondary Recovery ◽  
Low Interfacial Tension ◽  
Recovery Methods

In conditions of declining production and significant watercut in most of producing oil fields in Western Siberia, secondary recovery methods such as waterflooding are ineffective. Promising methods for increasing oil recovery are chemical enhanced oil recovery methods such as surfactant-polymer (SP) flooding. Designing the chemical composition for SP flooding one should take into account the geological, physical and geochemical features of the oil field: reservoir temperature, composition and properties of reservoir fluids and rocks. The aim of the article is to create the optimum formulation of surfactant-polymer system for certain oil field in Western Siberia. The integrated laboratory studies are conducted to prove successful of SP formulation. The aqueous solubility, phase behavior experiment, low interfacial tension, admissible values of dynamic adsorption and oil produced (40 %) during coreflood experiments shows that SP formulation T01 meet the requirements for effective SP flooding.

scholarly journals Gas Lift Performance of Some Horizontal Wells in Ahdeb Oil Field

2021 ◽  
Vol 7 (3) ◽  
pp. 66-74
Author(s):  
Dr. Kareem A. Alwan ◽  
Dr. Maha R. Abdulameer ◽  
Mohammed Falih
Keyword(s):  
Water Injection ◽  
Injection Pressure ◽  
Oil Field ◽  
Reservoir Pressure ◽  
Injection Wells ◽  
Artificial Lift ◽  
Electrical Submersible Pumps ◽  
Optimal Injection ◽  
Water Cut ◽  
The Impact

Ahdeb is one of the Iraqi oil fields, its crude characterized by medium API (22.5-28.9) and highly reservoir pressure depletion from Khasib formation due to lack of water drive. This makes it difficult to produce economic oil rates. Therefore, many water injection wells were drilled by the operators to maintain the reservoir pressure during production. In addition to that, electrical submersible pumps (ESP) were used in some productive wells. This study suggests exploitation of gas associated with oil production to be recycled to lift oil as a substitute for the ESP .The work in this study includes using PIPSIM software to build a model of four studied productive wells (AD1-11-2H, AD2-15-2H, AD4-13-3H, A4-19-1H) after choosing the suited correlation for each well. According to the statistical results, Mukherjee & Brill correlation is the best option for all wells. The use of PIPESIM software include determining artificial lift performance to determine the optimum amount of gas injected, optimum injection pressure as well as the optimum injection depth and knowing the impact of these factors on production, as well as the determination of the optimal injection conditions when water cut changes. According to the current circumstances of the wells, the depth optimized for injection is the maximum allowable depth of injection which is deeper than the packer by 100 ft and the amount of injection gas is (1.5, 1, 1, and 1) MMscf/day for wells (AD2-11-2H, AD2-15-2H, AD4-13-3H, and AD4-19-2H) sequentially and injection pressure (2050, 2050, 2050, and 2000) psi for wells (AD2-11-2H, AD2-15-2H, AD4-13-3H, and AD4-19-2H) sequentially.  

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