Scale Squeeze Inhibitor as Preventive Treatment in Brani Wells, Offshore North West Java

2021 ◽  
Author(s):  
Hendro Vico ◽  
Riezal Arieffiandhany ◽  
Indra Sanjaya ◽  
Lambertus Francisco ◽  
Yasinta Dewi Setiawati ◽  
...  
Keyword(s):  
Oil Production ◽  
Production Performance ◽  
Carbon Dioxide Partial Pressure ◽  
Scale Inhibitor ◽  
Dissolved Carbon ◽  
Laboratory Test Results ◽  
Intervention Cost ◽  
Yearly Average ◽  
Scale Deposits ◽  
Inhibitor Treatment

Abstract The Brani-Field is located offshore Northwest Java and currently produces hydrocarbons from a sandstone reservoir with an average watercut of 83%. Some high watercut wells are prone to scale problems and need repetitive clean outs to overcome production decline. In 2019, downhole scale inhibitor treatment was evaluated and planned for application in these wells. Scale inhibitors are able to prevent the formation of scale so the well is able to deliver higher average oil production with lower intervention cost. In Brani wells, scale deposits are formed in perforations, downhole completion equipment, and flowlines depending on the water composition, temperature, and a reduction in dissolved carbon dioxide partial pressure. These scales deposits restrict the fluid flow causing significant production loss. In extreme conditions, the production tubing was blocked completely with the scale deposits and cease the production. Normally, the scale restriction problem in Brani wells were handled by a combination of mechanical and acidizing treatment using Coiled Tubing (CT) for downhole completion and acidizing treatment for flowline restrictions. These treatment were performed periodically every 2-4 months depending on well conditions with scaling becoming more severe in higher watercut wells. From an economic standpoint, current scale treatment methods lead to very high well intervention costs due to expensive liftboat and CT unit daily rates. The economics of these conventional treatments is further deterred by low yearly average oil production. Evaluation for scale inhibitor treatment started with the candidate selection, fluids compatibility test, core re-gain permeability test, and economic evaluation. BRG-10 well was selected as first candidate due to scale problem severity and low oil production rate. This well normally delivers 140 bopd with 90% watercut, but scale build up in the tubing and flowline prevented the fluids flow and lowered the production to 30 bopd in just two months. Laboratory test results demonstrated that the core regained permeability with the main pill fluids to a relatively high, 77.96% without any fluids compatibility issues. Deployment of a scale inhibitor squeeze treatment in BRG-10 well was executed in Jan 2020 by bullheading 657 bbl inhibitor fluids into the formation. The well was then shut in for 24 hours of soaking time. The post treatment results showed a very promising result with much more stable oil production after 11 months treatment, welltest on December 2020 showed the well was still producing 130 bopd with 90% watercut. Following the successful application in BRG-10, the scale inhibitor treatment was applied in other wells, BRK-7 in June 2020 and BRG-5L in August 2020. So far, those two wells show good production performance with 93 bopd with 85% watercut for BRK-7 and 264 bopd with 76% for BRG-5L.

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.

Unlocking By-Passed Oil with Autonomous Inflow Control Devices Through an Integrated Approach

2021 ◽  
Author(s):  
Pawan Agrawal ◽  
Sharifa Yousif ◽  
Ahmed Shokry ◽  
Talha Saqib ◽  
Osama Keshtta ◽  
...  
Keyword(s):  
Continuous Production ◽  
Oil Production ◽  
Gas Production ◽  
Oil Field ◽  
Production Performance ◽  
Fluid Distribution ◽  
Flow Profile ◽  
Horizontal Drain ◽  
Control Devices

Abstract In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough. Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios. The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir. Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their long-term viability.

Increasing Treatment Lifetime through Sustained Release of Scale Inhibitor from Scale Inhibitor Nanoparticles

SPE Journal ◽  
2021 ◽  
pp. 1-7
Author(s):  
Huili Guan ◽  
Austin Lim ◽  
Joshua Hernandez ◽  
Jenn-Tai Liang
Keyword(s):  
Sustained Release ◽  
Functional Group ◽  
Proof Of Concept ◽  
Linear Scale ◽  
Scale Inhibitor ◽  
Concept Study ◽  
Inhibition Concentration ◽  
Calcium And Magnesium ◽  
Inhibitor Treatment ◽  
Over Time

Summary Scale can cause flow assurance issues because of damage to the near-wellbore region and in production facilities. Scale inhibitors are often used to help mitigate these problems. The main focus of this proof-of-concept study is to examine the ability of a newly developed crosslinked nanosized scale inhibitor (NSI) particle to inhibit scale formation through sustained release of scale inhibitor into a model brine and increase scale inhibitor treatment lifetime. Results from minimum inhibition concentration (MIC) measurements showed that, at 95°C, the MIC decreased gradually from 10 ppm at day 0 to 5 ppm after 9 days and eventually reached a very low MIC of 2 ppm after 49 days. These findings are consistent with our hypothesis that the sustained release of linear scale inhibitor from the NSI would result in a decrease in MIC over time caused by an increased amount of linear scale inhibitor being released into the model brine. Also, attaching 2-acrylamido-2-methyl-1-propanesulfonic functional group (AMPS) to NSI successfully inhibits the pseudoscale formation when the scale inhibitor comes into contact with the calcium and magnesium in the model brine. Results from sandpack floods showed that NSI increased the treatment lifetime from 3 pore volumes (PV) postflush throughput, for the traditional scale inhibitor, to 35 to 105 PV postflush throughput. These results support our hypothesis that sustained release of the trapped NSI nanoparticles can improve the treatment lifetime.

First Successful Autonomous ICD Pilot for GOR Management Across ADNOC Offshore

2021 ◽  
Author(s):  
Fazeel Ahmad ◽  
Zohaib Channa ◽  
Fahad Al Hosni ◽  
Salman Farhan Nofal ◽  
Ziad Talat Libdi ◽  
...  
Keyword(s):  
Oil Production ◽  
Pilot Project ◽  
Gas Production ◽  
Simulation Software ◽  
Production Performance ◽  
Production Operation ◽  
Open Hole ◽  
Early Production ◽  
Horizontal Wellbore ◽  
Selection Factors

Abstract The paper discusses the pilot project in ADNOC Offshore to assess the Autonomous Inflow Control Device (AICD) technology as an effective solution for increasing oil production over the life of the field. High rate of water and gas production in horizontal wells is one of the key problems from the commencement of operation due to the high cost of produced water and gas treatment including several other factors. Early Gas breakthrough in wells can result in shut-in to conserve reservoir energy and to meet the set GOR guidelines. The pilot well was shut-in due to high GOR resulted from the gas breakthrough. A pilot project was implemented to evaluate the ability of autonomous inflow control technology to manage gas break through early in the life of the well spanned across horizontal wellbore. And also to balance the production influx profile across the entire lateral length and to compensate for the permeability variation and therefore the productivity of each zone. Each compartment in the pilot well was equipped with AICD Screens and Swell-able Packers across horizontal open hole wellbore to evaluate oil production and defer gas breakthrough. Some AICDs were equipped with treatment valve for the compartments that needed acid simulation to enhance the effectiveness of the zone. The selection factors for installing number of production valves in the pilot well per each AICD was based on reservoir and field data. Pre-modeling of the horizontal wellbore section with AICD was performed using commercial simulation software (NETool). After the first pilot was completed, a detailed technical analysis was conducted and based on the early production results from the pilot well showed that AICD completions effectively managed gas production by delaying the gas break through and restricting gas inflow from the reservoir with significant GOR reduction ±40% compared to baseline production performance data from the open hole without AICD thus increasing oil production. The pilot well performed positively to the AICD completion allowing to produce healthy oil and meeting the guidelines. The early production results are in line with NETool simulation modelling, thereby increasing assurance in the methods employed in designing the AICD completion for the well and candidate selection. This paper discusses the successful AICD completion installation and production operation in pilot well in ADNOC Offshore to manage GOR and produced the well with healthy oil under the set guidelines. This will enable to re-activate wells shut-in due to GOR constraint to help meeting the sustainable field production target.

The Cost and Value of Field, Laboratory, and Simulation Data for Validating Scale Inhibitor Treatment Models

2008 ◽  
Author(s):  
Jose Alejandro Patroni Zavala ◽  
Eric James Mackay ◽  
Oscar Vazquez ◽  
Lorraine Scott Boak ◽  
Michael A. Singleton ◽  
...  
Keyword(s):  
Scale Inhibitor ◽  
Simulation Data ◽  
Field Laboratory ◽  
Treatment Models ◽  
The Cost ◽  
Inhibitor Treatment

A New Artificial Intelligence Method to Predict Water Flooding Performance in Layered Reservoir

2021 ◽  
Author(s):  
Cunliang Chen ◽  
Xiaodong Han ◽  
Wei Zhang ◽  
Yanhui Zhang ◽  
Fengjun Zhou
Keyword(s):  
Artificial Intelligence ◽  
Numerical Simulation ◽  
Computing Time ◽  
Vertical Direction ◽  
Single Layer ◽  
Oil Production ◽  
Oil Field ◽  
Production Performance ◽  
New Method ◽  
Water Flooding

Abstract The ultimate goal of oilfield development is to maximize the investment benefits. The reservoir performance prediction is directly related to oilfield investment and management. The traditional strategy based on numerical simulation has been widely used with the disadvantages of long run time and much information needed. It is necessary to form a fast and convenient method for the oil production prediction, especially for layered reservoir. A new method is proposed to predict the development indexes of multi-layer reservoirs based on the injection-production data. The new method maintains the objectivity of the data and demonstrates the superiority of the intelligent algorithm. The layered reservoir is regarded as a series of single layer reservoirs on the vertical direction. Considering the starting pressure gradient of non-Newtonian fluid flow and the variation of water content in the oil production index, the injection-production response model for single-layer reservoirs is established. Based on that, a composite model for the multi-layer reservoir is established. For model solution, particle swarm optimization is applied for optimization of the new model. A heterogeneous multi-layer model was established for validation of the new method. The results obtained from the new proposed model are in consistent with the numerical simulation results. It saves a lot of computing time with the incorporation of the artificial intelligence methods. It showed that this technique is valid and effective to predict oil performance in layered reservoir. These examples showed that the application of big data and artificial intelligence method is of great significance, which not only shortens the working time, but also obtains relatively higher accuracy. Based on the objective data of the oil field and the artificial intelligence algorithm, the prediction of oil field development data can be realized. This technique has been used in nearly 100 wells of Bohai oilfields. The results showed in this paper reveals that it is possible to estimate the production performance of the water flooding reservoirs.

Modelling and Optimisation of Flow Control Valves Case Study From the Greater Burgan Field, Kuwait

2020 ◽  
Author(s):  
Mustafa Al-Hussaini ◽  
Hamad Al-Kandari ◽  
Ravi Kurma ◽  
Kishore Jyoti Burman ◽  
Wuroud M. Al-Fadhli ◽  
...  
Keyword(s):  
Flow Control ◽  
Net Present Value ◽  
Dynamic Modelling ◽  
Oil Production ◽  
Production Performance ◽  
Capital Outlay ◽  
Water Production ◽  
Control Valves ◽  
Sector Model ◽  
Well Completion

Abstract This paper describes a dynamic modelling and optimization study to investigate the viability of deploying intelligent completions for well management in a mature oilfield in order to mitigate the challenges of increasing water cut and rapid diminishing of surface locations for new wells across the Greater Burgan field. Reservoir simulation is used to assess the potential benefits of installing Flow Control Valves (FCVs) in a candidate well, to control production from multiple reservoir zones. A representative sector model is defined around the candidate well, to include surrounding wells that could influence its flow behaviour. Reservoir properties are extracted from a fine-scale geological realization and updated using current well logs. Sensitivity studies are performed to determine the appropriate size and grid design for simulation. The well is planned to be completed across six producing reservoir zones with a single tubing and an Electrical Submersible Pump (ESP). In the optimization strategy, the FCV aperture openings are adjusted over the lifetime of the well, to maximize the Net Present Value, while meeting operational and strategic constraints. The robustness of the forecast outcomes are highly dependent on the quality of reservoir characterization. A sector model large enough to represent the effects of reservoir heterogeneities and interference from other wells, was used. The efficient optimization workflows used here can be generalized for similar analyses of other wells and other fields. The optimized results demonstrate that installation of FCVs can help to meet the simultaneous objectives of boosting oil production while reducing water production. This is achieved by choking back the deeper high-water production zones to accelerate oil production from the upper high oil saturation zones, while also targeting offtake to induce the shallower low-pressure zone to deliver more. The large initial capital outlay, comprising the equipment and service cost of the FCV installation is fully offset within the first year of production, post installation. This study highlights the significant upside benefits for the management of complex brown fields such as the Greater Burgan by adopting smart well completion strategy. Improving well production performance, and supporting multi-zone completions, should also enable reduction of well counts for fields with existing high well density and lack of surface space to accommodate many new dispersed wells.

Expansion of Data Analytics for Optimizing Steamflood In Mukhaizna Heavy Oil Field

2021 ◽  
Author(s):  
Mohammed Al Asimi ◽  
Nasar Al Qasabi ◽  
Duc Le ◽  
Yuchen Zhang ◽  
Di Zhu ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Data Analytics ◽  
Oil Production ◽  
Steam Injection ◽  
Lessons Learned ◽  
Oil Field ◽  
Production Performance ◽  
Optimization Process ◽  
Successful Implementation ◽  
Full Field

Abstract After successful implementation of data analytics for steamflood optimization at the Mukhaizna heavy oil field in Oman late 2018, Occidental expanded the project to two additional areas with a total of 626 wells in 2019, followed by full field coverage of more than 3,200 wells in 2020. In 2019, two separate low-fidelity proxy models were built to model the two pilot areas. The models were updated with more features to account for additional reservoir phenomena and a larger scope. On the proxy engine side, speed and robustness were improved, resulting in reduced CPU processing time and lower cost. Because of advancements in software programing and the pilots’ encouraging production performance, full-field coverage was accelerated so the model could support the efforts in optimizing steam injection during the 2020 OPEC+ production cut, not only to comply with allotted quotas, but also to allocate the resources optimally, especially the costly steam. Good improvements have been observed in overall steamflood performance, the models’ capabilities, and the optimization workflow. The steam/oil ratio has been reduced through the increase in oil production in both expanded study areas while keeping the total steam injection volume constant. Overall field steam utilization was improved both during the 2020 OPEC+ production cuts and during the production ramp-up stage afterward. With the continuous improvement in supporting tools and scripts, most of the steam optimization process steps were automated, from preparing, checking, and formatting input data to analyzing, validating, and visualizing the model outputs. Another result of these improvements was the development of a user-friendly web application to manage the model workflow efficiently. This web app greatly improved the process of case submittals, including data preparation and QC, running models (history matching and forecasting), as well as visualization of the entire workflow. In terms of optimization workflow, these improvements resulted in less time spent by the field optimization engineer in updating, refreshing, and generating new model recommendations. It also helped reduce the time spent by the reservoir management team (RMT) to test and validate the new ideas before field implementation. This paper will describe the improvements in the proxy model and the overall optimization process, show the observed oil production increases, and discuss the challenges faced and the lessons learned.

Development of Tight Upper Cretaceous Reservoir in Offshore Black Sea Adds Life to a Mature Asset

2021 ◽  
Author(s):  
I. Mitrea ◽  
R. Cataraiani ◽  
M. Banu ◽  
S. Shirzadi ◽  
W. Renkema ◽  
...  
Keyword(s):  
Black Sea ◽  
Upper Cretaceous ◽  
Rock Physics ◽  
Oil Production ◽  
Economic Life ◽  
Production Performance ◽  
Single Fracture ◽  
Well Performance ◽  
Acoustic Image ◽  
The Impact

Abstract This Upper Cretaceous reservoir, a tight reservoir dominated by silt, marl, argillaceous limestone and conglomerates in Black Sea Histria block, is the dominant of three oil-producing reservoirs in Histria Block. The other two, Albian and Eocene, are depleted, and not the focus of field re-development. This paper addresses the challenges and opportunities that were faced during the re-development process in this reservoir such as depletion, low productivity areas, lithology, seismic resolution, and stimulation effectiveness. Historically, production from Upper Cretaceous wells could not justify the economic life of the asset. As new fracturing technology evolved in recent years, the re-development focused on replacing old, vertical/deviated one-stage stimulations low producing wells with horizontal, multi-stage hydraulic fractured wells. The project team integrated various disciplines and approaches by re-processing old seismic to improve resolution and signal, integrating sedimentology studies using cores, XRF, XRD and thin section analysis with petrophysical evaluation and quantitative geophysical analyses, which then will provide properties for geological and geomechanical models to optimize well planning and fracture placement. Seven wells drilled since end of 2017 to mid-2021 have demonstrated the value of integration and proper planning in development of a mature field with existing depletion. Optimizing the well and fracture placement with respect to depletion in existing wells resulted in accessing areas with original reservoir pressure, not effectively drained by old wells. Integrating the well production performance with tracer results from each fractured stage, and NMR/Acoustic images from logs enhanced the understanding of the impact of lithofacies on stimulation. This has allowed better assessment and prediction of well performance, ultimately improving well placement and stimulation design. The example from this paper highlights the value of the integrating seismic reprocessing, attribute analysis, production technology, sedimentology, cuttings analysis and quantitative rock physics in characterizing the heterogeneity of the reservoir, which ultimately contributed to "sweet spot" targeting in a depleted reservoir with existing producers and deeper understanding of the development potential in Upper Cretaceous. The 2017-2021 wells contribute to more than 30 percent of the total oil production in the asset and reverse the decline in oil production. In addition, these wells have two to four times higher initial rates because of larger effective drainage area than a single fracture well. Three areas of novelty are highlighted in this paper. The application of acoustic image/NMR logging to identify lithofacies and optimize fracturing strategy in horizontal laterals. The tracers analysis of hydraulic fracture performance and integration with seismic and petrophysical analysis to categorize the productivity with rock types. The optimization of fracture placement considering the changes of fluid and proppant volumes without compromising fracture geometries and avoiding negative fracture driven interactions by customized pumping approach.

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