scholarly journals INTELLIGENT NATURAL DUMP FLOODING WELL - CASE STUDY FROM THE AREA OF THE WESTERN PERSIAN/ARABIAN GULF AND POSSIBLE APPLICATION IN THE CROATIAN MATURE OIL FIELD BENIČANCI

2020 ◽  
Vol 35 (4) ◽  
pp. 21-31
Author(s):  
Damir Zadravec ◽  
Vladislav Brkić
Keyword(s):  
Natural Water ◽  
Water Injection ◽  
Arabian Gulf ◽  
Pilot Project ◽  
Oil Field ◽  
Oil Reservoir ◽  
Reservoir Pressure ◽  
Well Completion ◽  
Execution Phase ◽  
Single Well

In the process of oil reservoir waterflooding, natural water dump flood technology for reservoir pressure decline prevention is considered as an unconventional but technically less demanding, more economical and safer method in comparison to surface power water injection. With natural dump flood technology, a single well serves as a water producer from a water bearing layer (aquifer) and simultaneously through gravity and the pressure difference between the aquifer and the depleted oil reservoir, it serves as a water injector inside the oil reservoir without expensive and complex injecting water treatment facilities at the surface. With the use of such technology and the running of intelligent well completion, it allows for the permanent monitoring of water production, injection rates and temperature inside the chosen reservoir. In addition, in offshore operations, the use of a subsea wellhead with a mud line suspension system allows for the placing of the injector well at the best predetermined position for water injection in a targeting reservoir and, together with an efficient subsurface acoustic data acquisition system, leads to better reservoir management and well integrity improvement. The overview and critical reflection of the drilling and intelligent completion of a natural dump flooding well for reservoir pressure support in partially depleted oil reservoirs in the Persian/Arabian Gulf has been given, referring to both their preparation and execution phase. The possibility of applying natural water dump flood was also considered in the Croatian onshore Beničanci oil field through a pilot project of water injection into the Be-62 well.

Low Capex ESP Powered Dumpflood Water Injector Pilot Improves M Field Recovery

2021 ◽  
Author(s):  
Peter Imoukhuede ◽  
Akin Obe ◽  
Atuanya Chukwuma ◽  
Emeka Anyanwu ◽  
Oyie Ekeng ◽  
...  
Keyword(s):  
Water Injection ◽  
Cost Savings ◽  
Water Source ◽  
Pilot Project ◽  
Shallow Aquifer ◽  
Reservoir Pressure ◽  
Significant Cost ◽  
Deep Aquifer ◽  
Single Well ◽  
Discharge Pressure

Abstract The design of a gravity dump flood well for a depleted QG reservoir located offshore in M Field was significantly enhanced by the inclusion of an Electric Submersible Pump (ESP). This resulted in 1,500 barrels of oil per day production gain from producer wells in Area 2 of the reservoir that had become inactive due to low tubing head pressures with reservoir pressure depletion. The identification of an optimal water injector location to improve the low reservoir energy and sweep oil towards the existing producers was grossly challenged due to remote nature of existing wells from water injection facility. Significant cost implications exist for the construction of new pipelines to the Water Injection facility. In addition, the existing infrastructure is aged and degraded, creating a need for a cost-saving solution. The challenges were tackled by implementing a pilot ESP powered dumpflood in an ideally situated injector "Xi". With this technique, a single well acts as both the producer and injector, utilizing an ESP generated pressure differential to pump water from a deep aquifer to a shallow reservoir or boost natural gravity forces to reverse pump water from a shallow aquifer to a deeper reservoir (R. Quttainah 2001). The latter option proved ideal for this application given the shallower location of the water source relative to the target oil zone. By innovatively using Y-tool technology, the ESP reverse pumped 7,000 BWIPD at a discharge pressure of 772 psig from the upper "A" aquifer zone into the target oil QG reservoir within the same well at startup. The ESP motor was powered by a 4km electrical subsea cable to draw power from the field's Quarter Production Platform. Significant cost savings were achieved by eliminating the need for pipeline construction since water source and injection were combined in one well. Within 3-months of ESP startup, the target reservoir pressure boost resulted in the restoration of inactive wells and 1,500 BOPD incremental production gain from producers in Area 2 of the reservoir. Following the success of the ESP powered dumpflood pilot project with initial oil production gain of 1,500 bopd and significant cost savings, a study is ongoing for a field-wide deployment of the technique in field M and 2 neighbouring fields.

Diagnostic Plots for Production Decline During the Transition of Oil Field Development From Depletion to Water Injection

2021 ◽  
Author(s):  
Vil Syrtlanov ◽  
Yury Golovatskiy ◽  
Ivan Ishimov
Keyword(s):  
Water Injection ◽  
Simulation Models ◽  
Oil Field ◽  
Production Data ◽  
Oil Reservoir ◽  
Field Development ◽  
Well Production ◽  
Diagnostic Plots ◽  
Oil Field Development ◽  
Analytical Approaches

Abstract In this paper the simplified way is proposed for predicting the dynamics of liquid production and estimating the parameters of the oil reservoir using diagnostic curves, which are a generalization of analytical approaches, partially compared with the results of calculations on 3D simulation models and with actual well production data.

The Use of Tracer Technologies for Well Monitoring with Multi-Stage Hydraulic Fracturing on Bolshetirskoye Oil Field

2021 ◽  
Author(s):  
Ivan Krasnov ◽  
Oleg Butorin ◽  
Igor Sabanchin ◽  
Vasiliy Kim ◽  
Sergey Zimin ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Hydraulic Fracture ◽  
Horizontal Wells ◽  
Pilot Project ◽  
Oil Field ◽  
Well Completion ◽  
Construction Design ◽  
Multi Stage ◽  
Urgent Task

Abstract With the development of drilling and well completion technologies, multi-staged hydraulic fracturing (MSF) in horizontal wells has established itself as one of the most effective methods for stimulating production in fields with low permeability properties. In Eastern Siberia, this technology is at the pilot project stage. For example, at the Bolshetirskoye field, these works are being carried out to enhance the productivity of horizontal wells by increasing the connectivity of productive layers in a low- and medium- permeable porous-cavernous reservoir. However, different challenges like high permeability heterogeneity and the presence of H2S corrosive gases setting a bar higher for the requirement of the well construction design and well monitoring to achieve the maximum oil recovery factor. At the same time, well and reservoir surveillance of different parameters, which may impact on the efficiency of multi-stage hydraulic fracturing and oil contribution from each hydraulic fracture, remains a challenging and urgent task today. This article discusses the experience of using tracer technology for well monitoring with multi-stage hydraulic fracturing to obtain information on the productivity of each hydraulic fracture separately.

scholarly journals RESERVOIR PRESSURE MAINTENANCE BY WATER INJECTION INTO HORIZONTAL WELLS AT THE CONDITION OF THE GEOLOGICAL UNCERTAINTY IN CONTINENTAL DEPOSITS OF HIGH-VISCOSITYOIL OF PK1-3 FORMATION OF THE VOSTOCHNO-MESSOYAKHSKOYE OIL FIELD

2018 ◽  
pp. 44-50
Author(s):  
I. V. Kovalenko ◽  
S. K. Sokhoshko ◽  
N. N. Pleshanov
Keyword(s):  
Water Injection ◽  
Horizontal Wells ◽  
Oil Field ◽  
Reservoir Pressure ◽  
Geological Uncertainty ◽  
Continental Deposits

The article considers the problem of correct organization of the system of reservoir pressure maintenance by water injection into PK1-3 formation of the Vostochno-Messoyakhskoye oil field that has many geological uncertainties. To remove these uncertainties the authors offered the pilot well program of flooding system and detailed proposals for data diagnosis obtained during this program that will help to determine the most correct approach to the flooding system for this type of reservoirs.

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.

Applying Analytic Hierarchy Process to Determine Separate Layer Water Injection Rate of Single Well

2013 ◽  
Vol 734-737 ◽  
pp. 1354-1357
Author(s):  
Wu Yi Shan ◽  
Wei Lin Cui ◽  
Yong Sheng Li
Keyword(s):  
Analytic Hierarchy Process ◽  
Water Injection ◽  
Injection Rate ◽  
Oil Field ◽  
Analytic Hierarchy ◽  
Practical Applications ◽  
Separate Layer ◽  
Single Well ◽  
Water Cut ◽  
Hierarchy Process

The separate layer water injection rate determines the result of water injection. In the past, in order to inject a proper amount of water into different intervals, most of the time people would rely on their experiences. By employing this method, the amount of work was enormous and the result was not necessarily accurate. In this paper, five factors that would affect the water injection rate are taken into consideration, such as, thickness of the main well, the connected thickness, permeability, number of connected wells and oil saturation. A method of determining the proper water injection rate of single wells based on analytic hierarchy process is proposed. This method has been proven to be simple and accurate, the test result of a mathematical model also shows it fits the requirements of the oil field exploitation with current water cut and it is of great value to practical applications.

scholarly journals Production Allocation on Commingled Two Layer Well Using Fingerprint Method

2018 ◽  
Vol 1 (3) ◽  
Author(s):  
Fahrudin Zuhri ◽  
Rachmat Sudibjo ◽  
R. S. Trijana Kartoatmodjo
Keyword(s):  
Gas Chromatography ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Oil Field ◽  
Oil Reservoir ◽  
Production Time ◽  
Well Production ◽  
Well Completion ◽  
Production Allocation ◽  
Production Problem

<p>Production proportion ratio study of commingled well two layers reservoir has been developed by geochemistry approaching, with oil reservoir fingerpint methode by using Gas Chromatography then processed by Chemstation software. The study is developed to solve the commingled well production alocation problem in oil field. There are 4 oil samples will be analyzed to represent each layer and commingle production oil sample in 2009 and 2015.<br />Result of study, figures out that oil fingerprint from commingle production has a difference as long as production time. Oil sample that taken from different commingle production time is predicted to produce a different ratio contribution form each layer of reservoir. Every layer reservoir has a different contribution from 2009 to 2015. Result of production proportion ratio study can be applied to decisionmaking of reservoir developement in an oil field, especially for well completion and enhanced oil recovery. This methode is proven to be a solution of commingle production problem of two layers reservoir. Fingerprint methode to determine production proportion ratio of commingled well production is the first in Indonesia.</p>

scholarly journals PROBLEMS OF GEOECOLOGY IN THE FIELD OF RATIONAL NON-USE OF USE AND THE WAY OF THEIR SOLUTION

2018 ◽  
Vol 14 (1) ◽  
pp. 32-37
Author(s):  
Svetlana Nikolaevna Nagaeva
Keyword(s):  
Water Injection ◽  
Mineral Resources ◽  
Environmental Safety ◽  
Modern Technology ◽  
Reservoir Pressure ◽  
Protection Measures ◽  
Field Development ◽  
Technological Culture ◽  
Water Pumping ◽  
Single Well

All manifestations of technogenic changes in the depths in the search, exploration and development of oil fields can be very diverse and lead to many not always predictable consequences. The urgency of the task of integrated use and protection of mineral resources requires increased attention both to ensuring control over the implementation of environmental protection measures and for technologies that reduce the technogenic impact on it. The article considers the modern technology of water injection to maintain reservoir pressure in several layers at the same time with a single well, which increases the technological culture of field development, which positively affects the state of the subsoil and the environment. This technology is aimed at reducing capital expenditures for the development of a system for maintaining reservoir pressure, the need to control and regulate the volume of water pumping through individual layers of the exploited facility. Introducing simultaneous-separate injection, it is possible to reduce the number of land-based water conduits, which ultimately leads to a decrease in the man-made load on the environment, ensuring environmental safety.

Applying BP Neural Network to Determine Proper Water Injection Intensity of Water Drive Oil Field

2013 ◽  
Vol 734-737 ◽  
pp. 1358-1361
Author(s):  
Wu Yi Shan ◽  
Wei Lin Cui ◽  
Yong Sheng Li
Keyword(s):  
Neural Network ◽  
Neural Network Model ◽  
Bp Neural Network ◽  
Water Injection ◽  
Injection Rate ◽  
Influential Factors ◽  
Oil Field ◽  
Well Water ◽  
Network Data ◽  
Single Well

In this paper, combining previous research on methods of determining water injection rate, dividing coefficient is introduced into this process. Influential factors of water injection rate are also taken into consideration. Based on those theories mentioned above, an analysis on determining dividing coefficient is made by applying BP neural network. Data from one particular year of exploitation was chosen to build up a neural network model between the dividing coefficient and other factors to determine the dividing coefficient, and then single well water injection rate was determined.

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