bluuebunny/crossref_metadata_2025 huggingface dataset:
Energy Efficiency Improvement of a Gas Compressor Through Process Parameters Adjustments
Authors: Al-Mulhim Abdulaziz A.
Published: October 2022

As a global leader in energy supply, Saudi Aramco spares no efforts in maintaining the global energy demand by operating major onshore and offshore oil fields. This comes while ensuring to minimize the carbon footprint that will be resulted oil production, and to maximize the value creation from the operating facilities. The production of crude oil from these oil fields will involve producing associated gas at a facility that is called Gas Oil Separation plant (GOSP) which will be handled through gas gathering trains at the Gas Oil Separation Plants (GOSPs) to accommodate this valuable by-product with the produced crude oil from the connected oil field to increase the value creation and reduce flaring of the associated gas which may negatively impact the surrounding environment which includes but not limited to impacting climate change and air pollution. This is also part of Saudi Aramco commitments toward circular economy by reducing waste the amount of waste at the oil producing facilities.

Therefore, Saudi Aramco strives to improve energy efficiency at its premises. In spite of all the exerted efforts, strict policies, challenging targets and investments to achieve a continual improvement in energy efficiency, it would be hard to avoid a performance plateau without breakthrough solutions. This is particularly true in Saudi Aramco, considering the large geographical area in which different facilities are scattered.

Energy efficiency and environmental protection are two important parameters that are interconnected, and both are critical for the quality of future generation. Effective power utilization can eventually help sustainability and circular economy.
AutoBoost and Gas Lift System
Authors: Hadim Ammar , Kaci Yacine , Rahal Mohammed Lakhdar , Elfateh Sebaa Mohamed , Okba Mohammed Nadjib , Lachteg Mohamed , Allal Abdelhalim , Kasmiouri Mahmoud , Belbari Lahouari , Zeghdoud Aziz , Benie Christopher , Abdellah Mehdi
Published: October 2022

This paper will describe a new surface boosting system AutoBooST® used as an artificial lift, it can be defined also as a surface auto gas lift system, fully automated and self-powered with real time monitoring and optimization of well production. Sonatrach and Expro Gulf with its partner Innovative Production Services (IPS) have introduced this technology in Hassi Messaoud field to increase oil production from the low wellhead pressure wells located away from the central facility where gas lift network is already deployed, as well as the remote fields.

AutoBooST® operating principle is to separate the oil, water and gas at well level and re inject the separated gas into the well hence it is a system using the well associated gas as a gas lift and fuel gas of the unit which makes the unit fully autonomous with no external gas source nor energy requirement as the unit generates the necessary power to run all the utilities. Produced gas is recycled in a closed loop, therefore gas will be accumulated along with the operation and provides a wide range of gas rate to perform optimization of the gas lift injection parameters versus the produced oil. During the optimization or once optimum rate is set the excess of gas is diverted to the export line via an automated control valve.

For down hole part, two options were used for the gas injection point either down hole circulating device SSD or SPM to allow gas lift injection from annulus to production tubing_ unloading valves are not required since compressor discharge pressure can reach 160 bars_ or run concentric tubing 1.66 inside the production tubing as velocity string.

AutoBooST® application was very successful and gave an increase of production from 50% to 150%, particularly at well HMD-A with an increase from 2m3/h (301 bpd) @ Qginj = 0m3/d to 11 m3/h (1658bpd) @ Qginj = 23000 m3/d during the optimization phase then the well was set to produce at 6 m3/h (904 bpd) considering reservoir management aspects.

As in conventional gas lift the production increase depends mainly on the well and reservoir parameters hence candidate well selection is the key factor. AutoBooST® application was already extended to target two to three wells with one package knowing that a current unit max compression capacity is 25000 to 40000 m3/d which is prone to improvement, however it is possible to use several units at manifold level to cover a large number of wells which will make a remote mini gas lift station.

AutoBooST® is proven successful technology; it is an ideal solution for remote wells and fields. In addition to the production application it can be used to evaluate the gas lift conventional project prior to major investment decision.
Use of Virtual Metering to Maximize Water Injection Efficiency in an Offshore Field Abu Dhabi
Authors: Salimov Rail , Jaffres Benoit , Alblooshi Jamal , Sarsekov Arlen
Published: October 2022

In offshore field due to pessimistic design in one of the field, water injection flowmeters are not capable to measure full potential injection rates. Highly precise Virtual Metering methodology was developed in-house to estimate rates real-time using advanced analytics and machine learning algorithms. Main application of developed virtual meters are improvement in water injection allocation and Injectivity Index monitoring. For Injectivity Index monitoring a comprehensive methodology was developed to minimize uncertainties such as reservoir pressure and friction forces.

Virtual metering algorithms are based on choke position and pressure loss across the choke (Injection Header Pressure – Well Head Pressure). For all choke sizes with available data a quadratic regression (dP = A*Q^2+B) is fitted to observed data.

For intermediate choke position a polynomial is used to estimate "A" coefficient for any choke position. In case when no data is available to calibrate choke curves, additional step is introduced: total well head tower rate is estimated based on pressure loss between the wellhead towers.

Developed algorithms showed very high precision and accuracy. Backtested algorithm showed < 2.5 % error between estimated and measured rates. Developed Virtual Meter was main enabler for injecting at full capacity without limiting injection rates which had positive impact on field injection and production potential. Practical application of VM are rates allocation as well as injectivity index estimation. Injectivity index calculation methodology discussed in the paper takes into account transient and interference effect by building numerical model in well test interpretation software. Friction forces in the tubing are estimated with prosper model or pressure drop at the beginning of any PFO. Matched tubing friction curve will be used for continuous BHP calculation and precise II estimation. Transient II estimation is very important to understand injectivity index evolution and prompt any injectivity restoration actions if necessary.

Such Virtual Meters are novel in ADNOC group as discussed field is one of the first pilot green fields with available real-time data. Virtual Meters have zero CAPEX and OPEX as only existing hardware and software is used. Developed Algorithms can be upscaled in any asset as proven to be as a success story in discussed field in Offshore Abu Dhabi. All developed algorithms are embedded in commercial real-time monitoring systems and used for daily monitoring.
Advanced Vibration Analysis and Remnant Life Assessment to Maximize Plant Production Rates
Authors: Al Khoujah Khaled , Medina Antonio , Al Qaydi Juma , Al Mansoori Fatima , Frost Liam , McIlwraith Colin , Kaleem Daniyal
Published: October 2022

Oil and Gas facilities are often designed with production capacity margins of 10%-20% to allow for future expansions or modification on the facilities. Similarly, ADNOC Sour Gas has carried out a study to explore production expansion opportunities utilizing the existing facilities. The study included process and mechanical adequacy.

The study showed a limitation on one of the vessels due to dynamic stresses on various weld locations that had a history of failure, and accordingly, ADNOC Sour Gas conducted a measurement based dynamic stress assessment of the welded locations across 4 units. The study has recommended repair and modification work on various locations to ensure safe production increase.

ADNOC Sour Gas has successfully completed the verification and health check of the welds located on various piping and vessels that were limiting production capacity due to risk of various critical weld fatigue cracking and failure. A fatigue life assessment was conducted in-order to ensure safe and sustainable production and to explore the opportunity of a possible marginal production increase. This paper presents the detailed testing and simulation methodology including all technical specifications.
Un-Realize Application of LWD Multipole Sonic Tool for Evaluating Cement Quality: Optimizing the Well Operation in a Highly Deviated North Kuwait Deep Jurassic Well Case Study
Authors: Al-Mutawa Majdi , Saffar Ali Hussein , Al-Azmi Mejbel Saad , Al-Otaibi Fahad Barrak , Abdulmohsen Naser Bader , Ragaey Mohsen Mohammed , Kumar Joshi Girija , Alomar Abdulrahman Ahmad , Tiwary Devendra Nath , Pasaribu Ihsan Taufik , Al-Bannai Khaled , Kho Djisan
Published: October 2022

Cement quality is an important well integrity consideration to ensure proper hydraulic sealing. Traditionally, wireline cement bond logs have been used extensively in the Jurassic formation of North Kuwait. The case study well presented in this paper had an 80° inclination and 3,000 ft of a 6-in. open hole, which has remained opened for quite some time. Cement evaluation was required inside the 7 5/8-in liner to determine the cement quality behind the liner and integrity of liner shoe. This information is important for achieving a successful of multistage completion for the producing interval in the 6-in open hole.

The target interval had a vertical depth greater than 14,000ft from mean-sea level with a well deviation more than 80°. Four operational days were required to run drill pipe conveyance of conventional cement evaluation wireline tools. This operation would have exposed the 2,500ft of open hole to potentially collapsing situation due to the time dependence of the wellbore stability.

The capability of logging-while-drilling (LWD) multipole sonic tool for evaluating the cement quality was considered, as there was plan to acquire open hole log data using LWD technology, which included the LWD multipole sonic tool. While running in the hole to the open hole section, the LWD multipole sonic tool can acquire sonic-based cement evaluation data inside of the 7 5/8-in liner. This operating method consumes no rig time while obtaining the well integrity information.

This paper presents the case study, along with the LWD multipole sonic tool theory for measuring cement bond quality index, operation preparation, and the results of the data acquisition.
Innovative Approach to Maximize NGL Recovery Utilizing Process Modeling in Midstream Operations
Authors: Bu Ali Ahmed Khalid , Almusaiteer Mohammed Khalid , Sharaf Abdulaziz Saleh
Published: October 2022

The aim of this paper is to showcase successful operations of maximizing C2+ Natural Gas Liquids (NGL) recovery in a midstream NGL Recovery Plant utilizing process modeling and simulation.

Gas Treating Trains in Plant-A are designed to remove the CO2 from the sour feed gas using Di-Glycol Amine (DGA) and route the sweet gas to the NGL Recovery trains. To maximize the NGL recovery in Plant A, process modeling and simulation, using ProMax software, was utilized to identify any limitations in the Gas Treating trains and examine the possibility of processing higher feed gas than the design capacity. Main hydraulic parameters in the DGA absorber and regenerator were confirmed to be within the acceptable limit to handle additional amount of gas calculated from the simulation. A detailed procedure was prepared to process higher feed gas in the Gas Treating trains.

Processing higher feed gas at the Gas Treating trains has resulted in increasing the sweet gas production by 7% which was processed smoothly at the Gas Treating trains without abnormalities. Process parameters were closely monitored to ensure a safe and reliable operation. On-spec sweet gas was delivered which was verified by collecting gas samples and by monitoring the sweet gas CO2 online analyzer. In addition, no foaming symptoms were observed during processing the additional gas. The lean DGA and rich DGA velocities were below the maximum. The by-products of the DGA-sour gas reaction were maintained within the acceptable range which indicates that the reclaimer is functioning properly. Moreover, the lean DGA loading was acceptable and within the specification which is an indication of the DGA regenerator efficient operation. After completing all the required procedures and tests, it was concluded that the Gas Treating trains are able to process additional gas without adding any new equipment or modifying existing ones.

The success of maximizing the NGL recovery in Plant-A opens a new frontier for the oil and gas industry to boost the hydrocarbon production and create growth with the value-added of C2+ NGL capitalizing on the hydrocarbon value chain. An innovative approach that combines process simulation with actual implementation in the plant led to higher revenues with no capital expenditure.
Unlocking Drag Reducing Agent Systems Potential Using Data Analysis
Authors: Al-Aiderous Abdullah Younis
Published: October 2022

The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques to operate a Drag Reducing Agent system optimally, minimizing Drag Reducing Agent Losses and unlocking Drag Reducing Agent system's potential to increase facility throughput through pipelines. Drag Reducing Systems have recently received widespread industry adoption in various applications such as debottlenecking pipelines constraints, increase facility throughput and elimination of costly CAPEX. These proven data analysis techniques were used to tackle major and chronic issues associated with Drag Reducing Agents systems operation that led to excessive Drag Reducing Agent losses, Drag Reducing Agent system solidification and reduction in facility throughput and production. Drag Reducing Agent loss and solidification associated with system storage, handling and improper operations is the most important operating problem in the Drag Reducing Agent system and it represents a concern to the operation personnel. There are various types of Drag Reducing Agents classified by the type of carrier, each individual agent has its unique handling requirements and most optimum pipeline service usage.

In this paper, comprehensive data analysis of the potential root causes that aggravate undesired drag reducing agent losses, solidification and reduced throughput will be discussed along with solutions to minimize the expected impact. For example, operating the Drag Reducing Agent system at high temperature will increase the agent losses by solidification. In addition, improper agent circulation at the storage facility results in a reduction in agent efficiency as a result of carrier disengagement. This paper will focus on a detailed case study in one of the running Drag Reducing Agent systems at a gas-oil separation plant.
Enhanced Approach for Asphaltene Risks Study to Unlock Hundred Millions Barrels Stranded Oil
Authors: Kaouche Salim , Agrawal Pawan , Keshtta Osama , Bigno Yann , Elhassan Mohamed , Al Ameri Shaikh Rakkad , Al Ghailani Abdullah , Saidoun Mohamed
Published: October 2022

Severe Asphaltene deposition is encountered in some wells drilled in newly developed reservoirs of one of Abu Dhabi's giant offshore assets (Field AD), and for the first time, full well plugging with Asphaltene is experienced in the field. While successful curative clean up treatments are regularly made, the relatively high intervention frequency (once every month per well) has impeded the full-scale development of these reservoirs. This study shows how understanding the mechanism of Asphaltene stability/instability in field conditions can unlock the production of under-developed reservoirs (with hundred millions barrels of OIP) by anticipating and considering preventive measures during the design of new wells to limit Asphaltene deposition. In order to prevent the occurrence of Asphaltene deposition from reservoir formation to surface level, a Flow Assurance study was launched by the operating company with close support from the international partner. The objective was to determine the Asphaltene Deposition Phase Envelope (ADE) of the reservoir fluid by measuring onset pressures with Visual (High Pressure ‘HP’ Microscope) and Near Infrared Solid Detection System (SDS) as a function of 2 main variables: Different temperatures to investigate Asphaltene risks over the oil production pathway (at reservoir formation, and from wellbore to surface facilities) & Different Gas compositions to investigate the effect of rich Gas-Cap gas and injected lean gas on the Asphaltene stability. Also, the segregation of the nature of Asphaltenes within the reservoir has been investigated by using the experimental approach named ‘ASCI (Asphaltene Solubility Class Index) experiment’ introduced by the international partner (SPE-164184) to rank Asphaltenes’ solubility with atmospheric dead oil samples taken in different locations.

In addition to that, 2 more experiments were performed: Organic – Inorganic test on solid sample to determine the composition and the nature of the solid deposit (whether it is Asphaltene or other type of depositions) & SARA analysis on atmospheric samples.

This paper presents the improved work-flow based on the collaboration of the local operator and the international partner, introduces the use of ASCI (Asphaltene Solubility Class Index) experiment and discusses the results of the study and its way-forward.
Challenging Traditional Practices in Conventional Reservoirs: Overflushing, Water Conformance and Pillar Fracturing Combination, S Field, Ecuador
Authors: Izurieta Alvaro Javier , Padilla Wilson Leonardo , Mayorga Christopher Jonathan
Published: October 2022

We discuss the application of overflushing along with pillar fracturing in a mature oilfield in Ecuador, where an effective high conductivity (high proppant concentration) fracture is required to enhance productivity because of low reservoir pressure and high permeability. Hydraulic fracturing is a proven technology used in the Oriente Basin with three challenges that remain constant (1) maximize conductivity and (2) reduce proppant flowback risk in the production stage and (3) reduce well intervention time.

To address these challenges a combination of overflushed pillar fracturing, and tip screen out (TSO) are proposed. We show the reservoir analysis, laboratory tests and hydraulic fracture modeling performed to support the implementation of overflushing. Reservoir analysis includes a methodology used to execute an optimized fracture design, and laboratory tests include core flow tests that define non-damaging fluids to be used during workover and fracturing operations, and relative permeability modifiers (RPM) for water conformance. Relevant results are also presented using three key performance indicators (KPI) to evaluate the effectiveness of resin-based pillar fracturing with overflushing viz., (1) pressure buildup data (2) fluid production and (3) productivity index increase post fracturing. Three case studies are presented for fracturing candidates with special conditions, that show that this technique can be extended beyond the traditional job.

Pillar fracturing (fracture and refracturing jobs) combined with overflushing in conventional reservoirs is documented for the first time, with effective stimulation results. This study applies overflushing, a practice developed for completion efficiency in unconventional reservoirs, and combines it with already proven practices in mature conventional reservoirs (pillar fracturing, customized fluids, 3D fracture design, and water conformance while fracturing) with a positive effect on production enhancement and proppant flowback risk reduction. Pressure buildup tests confirm no adverse effect of overflushing since negative skin or bilinear flow is observed, along with an increase in fluid production and productivity index in the studied wells.
Steamflooding Sandstones by Converting Horizontal Producers to Horizontal Injectors with Different Flux Rates
Authors: Al Aamri Rawa'a Mubarak , Al Bulushi Hussain Ali , Al Ajmi Zainab Mohammed , Al Shukri Yahya Mohammed , Al Mazrooe Ibrahim Khalfan , Bait Khalifa Hamid Sanjoor
Published: October 2022

Located in southern Oman, the Mukhaizna heavy oil field has been under steamflood since 2007, but a shallower reservoir was later discovered in a flank area with no steam injectors nearby to extend thermal support to the new zone. The big challenge with cold production in this zone was the steep decline rate, which reached up to 50% per year. Multiple Horizontal Producers (HPs) are at pump-off condition (POC) and are working on a timer mode because there is insufficient inflow to keep the pump running 24 hours a day. The objective of this project was to steamflood this shallow sandstone reservoir to enhance its performance and productivity.

A trial "with two pilots" was carried out in which the middle well of three HPs was converted to a Horizontal Injector (HI) to monitor steam injectivity, the response in the outer two producers, and the improvement in their productivity indices. The selection criteria were based on sand property similarities, channel continuity deduced from the seismic and geological interpretation, cross-sections, reservoir pressure, and production data that showed interference. The spacing between the HI and HP wells was considerable at 250 m, but the injected steam quality (SQ) for the First Phase was hovering around 99%, which is considered excellent.

There were two phases in the trial, each lasting 6 months. The HP to HI conversions were done in December 2020 in two locations at different flux rates "which had negligible effects". Water cut increased significantly in both locations without any clear heat signals. The breakthrough was confirmed by taking salinity samples from the outer HPs. Some interesting observations and learnings have been extracted from the trial, which opened the door for new ideas to be examined.
Case Study of First Successful Aqueous Based In-Situ Formation Consolidation Treatment in the Gialo Field, Libya
Authors: Ghonim Ahmed ElSayed , Khalifa Mohamed , Palanivel Maharaja , Fuser Colby , Shengarou Hamza , Aljwili Aimen , Elusta Shaaban , Abouzenen Fathi , Etabib Abdulaati , Etajri Mosaab Mohamed
Published: October 2022

Sand production is a major challenge for many oil and gas industry operators, especially with unconsolidated reservoirs with weak bonding between the sand grains that enter the wellbore. This can eventually lead to damage to production lines and erosion effects to other surface equipment along with well productivity when drawdown exceeds the critical drawdown pressure. Although several techniques are used globally to combat sand production, most are uneconomical when considering the risk versus reward and the overall effectiveness in controlling sand production.

An aqueous-based resin consolidation technique was evaluated for application in this case after the mechanical properties of the formation and sanding behavior in the field were estimated to be in the acceptable range for this technique to be applied successfully. An injection test followed by the aqueous-based consolidation treatment was bullheaded into the sand-producing zone resulting in minimal rig up and equipment required to operate. Post-treatment, a curing period allowed the resin to consolidate the coated sand grains.

Compared to conventional resin, which requires large volumes to coat the near-wellbore region, this treatment used only a small volume of active resin. This effectively coated and cured in the near-wellbore region, providing excellent consolidation strength allowing the well to produce without any sand particles under the same drawdown applied to offset wells in the field.

A case study is presented in this paper illustrating an effective, cost-efficient, and proven sand control solution for the high potential reservoirs of Libya. This solution can help develop fields that previously suffered from impaired well productivity and required expensive formation sand handling and disposal. Such a solution restored oil production without any considerable effects on the relative permeability of the formation to hydrocarbon or water while maintaining sand consolidation without any further sand production problems.
Successful Delivery of a Breakthrough Implementation of Novel Well Testing Operation Philosophy: Open Sea Extended Well Testing Operation with Temporary Tanker for Crude Evacuation and Storage for Field S Appraisal Project in Malaysia
Authors: Hamid S. Abd , Abdullah S. , Chan W. , Mokhtar Z.
Published: October 2022

Reservoir connectivity and productivity uncertainty can be reduced through the application of an extended well testing (EWT). In the open sea condition, this approach project incurs huge monetary commitment and to reduce this, recovery from produced hydrocarbon is necessary. Conventional open sea well testing is unable to recover the hydrocarbon as no storage facility is made ready. This paper presents the success story of a first application of open sea EWT operation in Malaysia in which it has proved the novel concept of an open sea EWT with the inclusion of Temporary Storage Tanker (TST) to complement the crude storage need, ability to recover and markets the production volume significantly improved the economic value. In addition, this novel method eliminates the practice of hazardous crude flaring activity, damaging emission from flaring was eliminated as well as significantly reduce the HSSE risk exposure.
Novel Machine Learning and Data Analytics Approach for History Matching Giant Mature Multilayered Oil Field
Authors: Suwito Edy , Sianturi Julfree Anto Dongan , Irawan Andi , Panjaitan Pahala Richard , Saeed Yawar , Priyanto Agus Dwi , Elfeel Mohamed Ahmed
Published: October 2022

This paper discusses an integrated reservoir study utilizing structured and novel machine learning and data analytics approach for history matching a giant mature multilayered oil field in Mahakam Delta of Indonesia. The unique reservoir modeling challenges and novelty of the data science methods will be presented, along with preliminary results and lessons learnt.

One of the most important elements in reservoir characterization and history matching process is integration between static and dynamic modeling. With numerous layers as study perimeter, a large number of uncertain parameters is unavoidable, from dynamic uncertainties such as hydrocarbon contacts and communication between regions to static properties like porosity, water saturation, etc. These in turn will create hundreds of possible scenarios during History Matching. Using python scripting embedded in the reservoir simulator and the agile reservoir modeling (ARM) approach, these uncertainties can be handled quickly, and each ensemble can be analyzed easily with Data Analytics and Machine Learning based proxy approaches.

The case study presented here is a giant mature oilfield with more than 50 zones and 100 contact regions. With more than 45 years of production and injection history, the conventional reservoir modeling where each zone is modeled individually and independently, assuming no communication between the regions, has been deemed as taking too much time and effort. The integrated approach bypasses this challenge by allowing simultaneous reservoir modeling as well as quick sensitivity analysis and history matching quality checking. Uncertainties were managed early on; for instance, the porosity model was generated through available algorithms and hydrocarbon contacts with Latin-hypercube sampling method. Preliminary results showed that overall time required to perform the modeling has been reduced significantly, while also establishing communication between the regions. Analytical aquifer modeling and communication between the regions were observed as the most sensitive parameters especially when matching the pressure behavior. Moreover, embedded python script and Data Analytics Dashboard have made it possible to perform fast and systematic analysis, thus more effort and time can be allocated to plan the way forward. The Machine Learning results will be further finalized at the next gate review, considering the project was initially proposed into several gates.

Static modeling using Machine Learning, coupled with dynamic modeling workflow and data analytics, has created a complete loop of reservoir study and characterization. All of these are conducted in a structured cloud-based platform, ensuring time-efficient process and repeatability while at the same time enabling hybrid approach by combining conventional method and advanced data driven approach
Deep Reservoir Conformance Control for the Wara Formation of the Greater Burgan Field: Lab Evaluation, Numerical Simulation and Field Implementation Design
Authors: Al-Murayri Mohammed Taha , Hayat Laila , Al-Qattan Abrar , Al-Kharji Anfal , Bouillot Jerome , Omonte German , Salehi Nazanin , Zaitoun Alain
Published: October 2022

Improving water-flood efficiency in heterogeneous reservoirs with high permeability contrast is of high strategic importance to maximize oil gains, debottleneck production facilities and alleviate water-handling constraints. This paper presents key lab, simulation and field design insights to implement Deep Reservoir Conformance Control (DRCC) in the Wara formation of the Greater Burgan Field. Prior technical assessment and high-resolution streamline modelling are covered in other technical publications.

Full-field high-resolution streamline reservoir simulations have been used to identify 23 candidate injectors for DRCC. The wells having one layer taking more than 50% of the total water injected were considered as good candidates for DRCC to mitigate water channeling challenges and increase sweep efficiency accordingly.

Mechanical water shut-off options were considered, but it was confirmed that near-wellbore solutions do not adequately address deep reservoir conformance issues and can compromise water accessibility to unswept oil zones. Furthermore, mechanical water shut-off options require recompletion and can be expensive and difficult to deploy.

To overcome these drawbacks, DRCC has been evaluated in an integrated laboratory and simulation study to design a field implementation plan. The recommended DRCC approach involves injecting a microgel followed by a gel. The microgel enables deep treatment while the gel strengthen Permeability Reduction near the well.

Laboratory evaluation qualified a microgel having a size of around 2 µm and a gel combining water-soluble polymer with an organic crosslinker. Gelation time was 2 days and full gel consistency was obtained after two weeks, under the form of a strong and slightly deformable gel (E-F on Sydansk scale). Permeability reduction post gelation was as high as 10,000 times.

Reservoir simulations were executed to validate this approach, size-up the treatment and forecast performance. A pattern involving an injector and a producer well was selected. Laboratory coreflood data were used as input for the simulations. The combination of microgel followed by gel with a total volume of around 6000 bbl, pumped in two days, induces a gain in oil production of around 20 to 50% in 10 years. Simulation shows improvement of both vertical and areal sweep efficiency. Moreover, the gain appears very early after chemical injection.

The combination of microgel and gel gives an efficient in-depth conformance system that can increase waterflood efficiency in formations such as Wara. This innovative approach has high potential in multi-layer high-permeability heterogeneous sandstone reservoirs.
EOR Signature in Carbonate Reservoirs from Extended Low-Salinity Waterflooding in Oman
Authors: Al Busafi Badar Salim , Al Rawahi Nuzha
Published: October 2022

Low-salinity Enhanced Oil Recovery (EOR) signatures have been well proven by numerous lab and field trial studies (Zhang et al., 2007; Austad et al., 2008; Yousef et al., 2013; Al-Busafi et al., 2014). The evidence is very strong in clastic formations, even extending to full-field application evidence (Seccombe et al., 2010). However, low-salinity EOR in carbonate reservoirs is relatively underexplored and is still being studied in laboratory waterflooding tests and single-well trials. This is attributed to the lack of a single agreed physical model for the way low-salinity brine interacts with oil and carbonate rock surfaces under various subsurface conditions. Unlike sandstones, the reactive nature of carbonate rocks and the larger number of variables affecting the interactions have made the theory more complicated than clastic cases. For this reason, there are still some doubts about whether low-salinity EOR in carbonate rocks works or not. The conflicting arguments have made the oil industry very cautious of field applications in carbonates compared with sandstone reservoirs.

This work presents field evidence of waterflooding performance from long periods of low-salinity waterflooding in carbonate reservoirs in Oman. The fields were subjected to low-salinity water injection that was fifty times less saline than formation water. Two approaches were adopted to assess the benefit of low-salinity water injection. In the first example, history matching of long-term low-salinity water injection was used to infer the shape of the relative permeability curves. Those curves were compared to the lab-derived versions and to those from analogous fields that were subjected to formation water injection. The other approach compared data for extended periods of water injection from two patterns from the same field: one pattern was injected with low-salinity water (~4,000 ppm) and the other pattern was injected with produced formation water (~150,000 ppm). Plots of recovery factor versus pore volumes of brine injected were compared to observe differences in performance.

History matching results showed that the relative permeability curve had to be shifted from an oil-wet system to a water-wet system to achieve a good match. The resulting history-match curve was very different from the lab-measured relative permeability curve, which indicated an oil-wet system in this carbonate reservoir. The lab-derived curve was measured using a steady-state experiment with formation water. Furthermore, comparing the waterflood performance of the two areas with different salinities injected showed a clear distinction between their respective performance, with an 8-10% recovery factor difference after 0.3-0.4 pore volumes injected. Such observations support the argument that low-salinity waterflooding in carbonates has a long-term value that might not be easily observed from coreflooding tests in the laboratory or short field trials.
Evaluation of Alternative Polymers for Mangala Polymer Flood
Authors: Shankar Vivek , Sunit Shekhar , Zagitov Robert , Gupta Abhishek Kumar , Kumar Suresh , Kumar Ritesh , Pahari Kumarish , Agarwal Rahul , Nakutnyy Petro , Veerabhadrappa Santhosh
Published: October 2022

Mangala field is under polymer-flood since 2015. The polymer-flood is very successful in accelerating recovery compared to waterflood. As the flood matured, field performance indicated that part of the injected polymer was degrading in the reservoir. Lab studies and polymer samples collected from the reservoir suggest that the most likely reason of degradation is increased hydrolysis due to thermal ageing. This degradation compels higher dosing of polymer to make up for the lost viscosity and increases operating costs. Polymer precipitation in the reservoir may also lead to loss of reservoir permeability.

Literature survey and preliminary lab studies showed that polymers with Acrylamide-Tertiary-Butyl-Sulfonic acid monomer units (referred as ATBS polymers) could be a suitable option for Mangala. To evaluate the hypothesis, team did a series of lab and core flood studies. The studies include accelerated thermal ageing, rheology, dynamic adsorption, injectivity, water flood with fresh and degraded samples and compatibility studies with topside chemicals. Two HPAM polymers with different DOH and two ATBS polymers were evaluated. The selected ATBS polymer was then tested for compatibility with surface topside chemicals.

The studies show that the classic 20-25% DOH HPAM suffers viscosity degradation and possible precipitation in Mangala reservoir conditions. ATBS polymers and a lower DOH HPAM provide superior results to the incumbent HPAM with an acrylamide (86)-ATBS (14) copolymer providing the best results. ATBS polymers were especially resistance to cloud point lowering and provide some superiority in shear degradation. ATBS monomer was resistant to hydrolysis in the period of testing. Contrary to published literature ATBS polymers showed higher adsorption and their propagation through cores required higher pressure drop. ATBS polymer seemed to plug a low permeability section of the core stack. All polymers reach their peak viscosity at 30-40% hydrolysis and decline sharply after 40%. However, viscosity and cloud points measured during accelerated ageing are possibly conservative. A large-scale pilot of ATBS injection in Mangala is underway to validate the laboratory test results.

ATBS polymer can be a suitable polymer for some layers of Mangala with high residence time and permeability. The choice is driven by the economics of the incremental cost of ATBS for the benefits it offers. In some sands with shorter inter wells pacing, a lower DOH HPAM may work out to be a more cost-effective solution.

The study results provide insights to operators to understand the reservoir performance of existing polymer-floods and plan for future polymer-floods.
CO2 EOR Challenges and Opportunities to Enable CCUS Strategies
Authors: Pimenta Gervasio , Romero Carolina
Published: October 2022

This paper provides insights on the current challenges and opportunities associated with the development CO2 EOR projects as part of CCUS strategies. These projects are strategic for the oil and gas industry, not only mitigate the impact of GHG emissions from current operations, but also to enhance their oil recovery. The paper shares how lessons learned from ongoing CO2 EOR pilot projects in ADNOC Onshore have allowed the optimization of surface facilities, material selection for well completions and helped identify limitations to find solutions and proposals to deploy new technologies and enable CCUS strategies.

Since 2016, ADNOC Onshore has pioneered CO2 injection, both continuous and in WAG mode, using captured CO2 from Emirates Steel Industries under the Al Reyadah CO2 supply project (Sheikh, F, 2021; Hassan, S. et al 2021; Alklih et al 2019). Experience from the ongoing pilots was reviewed for potential cost optimization of the well design, while ensuring the same level of reliability and integrity of the completions from on-going Waterflood and HC WAG developments implemented in the same fields.

CO2 composition and fluid conditions were reviewed along with reservoir monitoring and log acquisition to study recommend strategies for WAG cycle changes that would mitigate potential corrosion issues.

Completions for CO2 WAG Injectors in ADNOC Onshore pilots have been traditionally applied in CRA material and employing wellhead heaters. These, represent high-cost elements in the drillex and CAPEX of WAG-CO2 development projects.

Results show that for WAG-CO2 projects L-80 1Cr materials may be used in WAG Injectors significantly lowering the Drillex costs. Mitigation strategies include the use of viscous fluid spacers that will limit the contact between CO2 and Water during cycle changes. Well head and down-hole temperature surveys showed that CO2 cooling effect under ADNOC Onshore field conditions was not a concern and long term injectivity has not been significantly affected. As a result, CO2 Heaters have been removed optimizing the CAPEX of on-going CO2 project studies
Field Development Simulation of a Mature Field with High Sealine Pressure and Well Eruptivity Issues
Authors: Koeck Charles-Henri , Agrawal Pawan , Goyal Praffula , Bensadok AbdelAziz , Madoz Alexis
Published: October 2022

Liquid loading is experienced in high water-cut wells operating against high sealine pressure in an offshore mature field without artificial lift. This phenomenon is usually not captured by VLP/IPR representation built into reservoir simulation or steady-state well models, which results in overestimation of future oil production. Key value drivers for the project are developing an understanding of the liquid loading based on critical fluid velocity, well completion and reservoir characteristics and study its impact on simulation forecasts.

Firstly, the liquid loading condition has been correlated to different well parameters such as productivity index, GOR and water-cut. The correlation is built from routinely acquired flow test data showing wells ceasing to flow due to unstable flow regimes and fluctuating sea line pressures. Additionally, extensive well modelling using Prosper software was carried out to assess the proper fluid correlation method. Secondly, that correlation was converted into a response surface model to make the link between the unstable flow regime conditions and the impacting parameters such as well PI, GOR, well geometry. Thirdly, the unstable flow correlation was implemented in the simulation model with a script of conditional events in order to flag wells with unstable flow and shut them if no activation condition is applied such as artificial lift or THP reduction.

Currently, it is estimated that about 4 wells are becoming unable to flow every year due to the mentioned loading issues. These loaded wells require vessel/barge to carry out unloading which involves significant operating cost in an offshore environment. This complex behavior is normally overcome by dynamically coupling the subsurface models to the surface production system. However, in a giant field with hundreds of wells from multiple reservoirs this can be complex and resource demanding.

Application of the correlation in the simulation resulted in about 80 wells with unstable flow conditions to be closed by year 2040, whereas they would have otherwise continued to flow if regular VLP curves were used. This method served to improve the model accuracy and to increase the assurance in forecasts predictability, with regards to water-cut evolution.

This study was a key driver input for deciding on the acceleration of a major debottlenecking facility related to medium pressure system at surface. Sustainability of field plateau, improved wells availability, reduced in-active wells count and associated reactivation resources are tangible benefits of the mentioned study.
Fiber Optic Surveillance for Water and Polymer Conformance Monitoring in an EOR Project in Petroleum Development Oman
Authors: Al Hashemi Mohammed Salim
Published: October 2022

The focus of this paper is to elaborate on the decisions taken based on the information obtained from the FO data in lab and field tests in polymer and water flood projects. It aims to provide insight into how Fiber Optic (FO) data through both Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) can be used to quantify in-well injection conformance for both water and polymer. The data was analyzed collaboratively between Shell and PDO and used to build a robust workflow to generate an inflow profile for either the water or polymer phase. Also, it has been used to assess Out-of-Zone injection, matrix versus fracture injection, and to prove conformance & injectivity improvement after acid stimulation. The output from FO compares favorably with other reference data such as PLT.

The paper will go through different aspects of workflow development covering all the methodologies used to convert FO data to inflow profile in flow rate. It will also provide information on how the obtained knowledge from this pilot can be replicated throughout various fields in and outside of Oman. The Fiber optic surveillance strategy for polymer flood has truly proven its value ready for potential upscaling for similar polymer projects.

FO data was acquired from permanent fiber installed behind the 7″ production casing from water and polymer injectors in a field in the South of the Sultanate of Oman. A total of 14 DAS and 9 DTS surveys were acquired in 7 water injector wells followed by additional 4 DAS surveys in polymer injectors wells. DTS data were acquired during several injections and shut-in periods to measure the warm-back transient conditions before full stabilization to (pseudo) geothermal temperatures. Data were processed and analyzed using a thermal simulation model to allocate and quantify injection conformance per zone. DAS data were acquired during injection with a minimum of three flow rates. The data were processed, time-averaged, and filtered to specific frequency bands to identify injection conformance.