bluuebunny/crossref_metadata_2025 huggingface dataset:
AI-Assisted History Matching Application to a Large Onshore Carbonate Reservoir
Authors: El Droubi N. , Tahir S. , Maarouf A. , Su S. J. , El Jundi O. , Kloucha C. Kada , Mustapha H.
Published: October 2023

History matching a large reservoir model with high well count and long production history might be a challenging and time-consuming task, especially if it's done using only global multipliers as advised by common practice. Using local modification is unavoidable. This paper describes the application of an automated workflow creating local modifications on well-by-well regions. This application is done on top of the global multipliers and all the other uncertainty parameters. It's done to generate an ensemble of simulation runs leveraging machine learning proxy models to history match a large onshore carbonate reservoir.

We applied a machine learning (ML)-based optimization process to perform history matching with a large number of uncertainties. A ML proxy-model was built from an ensemble of reservoir simulation models capturing varying uncertainty parameters. The ML proxy-model captured field and well level simulation results assessing the quality of the history match. An optimization framework was defined in which to embed the ML model, minimizing the mismatch between simulation results and historical production/injection. The objective function as defined assesses history match quality by comparing the historical production/injection data with simulation results predicted by the ML model.

The workflow was successfully applied to a large onshore carbonate reservoir with approximately more than 1000 wells and 20 uncertainty parameters. An ensemble of simulations was generated to capture the variation of the uncertainty parameters. This ensemble was used to train a high-fidelity reservoir proxy-model that predicts field level and well level simulation results. The optimization results provided a set of parameters by minimizing the mismatch between the results predicted by the ML model and the historical production/injection data. As a result, a high-quality history match was obtained on the key parameters considered. The results were then validated by running the reservoir simulation model with the optimum uncertainty parameters, which delivered results very close to the ML model prediction.

The optimization process with a ML model is orders of magnitude faster than attempting to perform the history matching using the reservoir simulation model. The ML-based optimization for the history matching framework developed demonstrated good results on a complex reservoir model with a high number of uncertainties and high well count, paving the way toward significant field development planning acceleration.
Innovative PDC Bit Design to Improve Drilling Performance in Highly Abrasive Sandstone Reservoirs
Authors: Hussain Sajid , Jose Bustamante Rodriguez Victor , Boufama Chaouki
Published: October 2023

Drilling heterogeneous and abrasive sandstone reservoirs horizontally with conventional PDC bits pose significant challenges due to early worn out cutters requiring multiple bit trips. This negatively impacts rate of penetration (ROP) resulting in excessive time to drill and complete horizontal sections. This paper describes how the use of rolling cutter PDC bit technology, can overcome this challenge by improving ROP to drill the entire section in optimal time.

A detailed analysis of historic drilling parameters and bit dull gradings in the field showed that abrasive wear and chipping on bit shoulders was the most common dull characteristic causing reduced ROP performance and requiring a BHA trip for the bit change-out. To address the challenge, finite element analysis (FEA) was performed to identify the locations of high cutter wear. Subsequently, a new bit design with fully rotating cutters strategically placed at high bit wear locations was developed. The new design ensures that the wear on diamond cutter faces is minimized, and prolongs bit life durability.

In order to test the efficiency of the bit, it was run on a motorized rotary steerable (MRSS) assembly to drill one of the horizontal sections with abrasive sandstone. The bit drilled the entire horizontal length of around 4000 ft in a single run. Previous bit designs drilled through similar reservoirs with multiple conventional PDC bits, or in the best-case scenario, with low ROP in a single bit run. The new bit design achieved unprecedented results by delivering ROP performance with an increase of 100% compared to the average bit run. This improved performance eliminated the risk of extended open hole exposure which often leads to wellbore instability induced by reactive shales, further warranting a dedicated reaming trip. Historic analysis also determined that conventional PDC bits fitted with premium cutters uses only a small portion of the diamond table to contact the formation. Once the diamond table on the cutters face gets worn or chipped, the drilling efficiency is compromised. These worn flat cutters generate a high degree of frictional heat while drilling through the abrasive sandstone, which breaks down the diamond bond. The new bit design with fully rotating cutter technology does not face the same challenge.

The paper will also discuss how precise positioning of the diamond cutting elements relative to contact with the formation is a prime concept to achieve efficient element rotation in order to keep the elements sharp for long intervals. As a result, roller diamond element bit durability is sustained and drilling run length is increased in comparison to conventional fixed cutter bits.
Innovative Method to Understand Flow Behavior in Horizontal Wells with Challenging Borehole Conditions Using Spectral Noise, High Precision Temperature and Pulsed Neutron Logs
Authors: Naser Ethar Al , Noureddine Benlakhdar
Published: October 2023

Understanding flow behavior in horizontal and highly deviated oil producers is crucial to optimize production strategies and ultimately improve hydrocarbon recovery. Traditionally, multi-phase production logging provides flow profiles and fluids entry points in horizontal wells. However, this technology may be less effective for boreholes with challenging conditions such as the presence of sticky material that cause the loss of measurement tool sensors. This paper proposes several techniques, including spectral noise logging, numerical temperature simulations, and pulsed neutron logging as alternatives to provide flow profiles, identify formation fractures, and characterize possible cross flows in horizontal oil producers with high water cut in the presence of sticky deposits.

The tool strings of spectral noise, high precision temperature and pulsed neutron logs contain no mechanical parts or exposed probes that could get affected by sticky deposits. The spectral noise log allows identifying flow zones and fracture signatures. An advanced numerical temperature simulator can be used to quantify total flow that correlates with changes in temperature gradients, while pulsed neutron logs provide water flow using carbon-oxygen for three-phase holdup thereby allowing oil flow to be estimated by subtraction the water flow rate from the total flow.

The presence of sticky deposits can compromise the ability of mechanical spinners and exposed probes to provide accurate flow profiles without the use of expensive chemical treatment. The proposed approach will provide a complete high-resolution flow profile comparable to mechanical spinners, while also looking deep into the reservoir and correlating the profile with borehole fractures. Also, the flow profile can be generated using the total acoustic noise power of the turbulent flow. The results of both numerical simulations and acoustic flow velocity compared well with the flow profile provided by the mechanical array production tools.

The combination of spectral noise, high precision temperature and pulsed neutron logging suite provides valuable reservoir information without the use of any mechanical parts or exposed probes that could be affected by sticky deposits.
Development and Evaluation of a Novel Non-Combustion Gas Turbine for Offshore Platform Application
Authors: Muhammad M. F. , Thant M. M. M. , Firmansyah Firmansyah , Daud N. M. R. N. M. , Sedaralit M. F.
Published: October 2023

In this paper, a series of steps for validating a Computational Fluid Dynamic (CFD) model of a novel impulse gas turbine generator is investigated. An impulse gas turbine generator is a small scale and compact electric generator designed to provide power to remote offshore platforms. The generator is driven by pressurized gas and generate power through expansion of the gas. As the effluent gas is designed to be redirected to lower pressure gas line, the generator provides clean energy with higher reliability and no dependency on weather if compared to solar panel technology that is widely used. As a new technology currently being developed and tested, the operating data of the generator is very limited, and the performance expected when deployed later cannot be ascertained. To ensure that the impulse gas turbine generator performs as per intended, numerical approach by using CFD is adopted where CFD model by using sliding mesh method have been developed. The simulations result is then validated with experiment results where the very small deviation is observed between the two results. With validated model, performance under natural gas or methane-rich condition is simulated and tested. Despite the different in gas composition, performance expected from CFD model is very similar to the actual result observed during the gas flow loop test.
Multizone Open Hole Gravel Pack Completion with Selective Production Capability in ACG Field
Authors: Susilo Yoliandri , Dharmadhikari Khsitij , Taha Sherif , Ismayilova Ayisha , Guliyev Ilkin , Jafarli Zaur , Kerimov Natig , Kerimova Ravana , Veliyev Samir , Whaley Kevin , Wallace Alex , Mammadov Elvin , Foster Mike
Published: October 2023

Azeri-Chirag-Gunashli (ACG) is a giant field located in the Azerbaijan sector of the Caspian Sea. The major reservoir zones are multi layers sandstone formations and weakly consolidated where Open Hole Gravel Pack (OHGP) completions have become the standard design for production wells. To date more than 170 high rate OHGPs have been completed that are producing comingled from multi-layered sandstone formation.

As the field matures, problems such as premature water and gas breakthrough are becoming increasingly common requiring the completion system to be inherently flexible to address such issues. The Multi Zone OHGP concept design has been developed to manage this increasing reservoir management complexity. Zonal isolation and selective production capability are achieved by installing combination of multiple Screen PBR and/or open hole packer in combination with seals unit and mechanical sliding sleeve in the inner string at the intermediate completion, and Inflow Control Valve (ICV) at the upper completion.

To date, two Multizone OHGP wells have been completed successfully. The Screen PBR system has proved to provide effective zonal isolation or baffling. This system allows flexibility to deal with unexpected reservoir surprise (wet/gas zone) that requires zonal isolation on day-1 without major changes in completion design, thus reducing rig time & operational cost.

This paper discusses design, execution, and result of the first two Multizone OHGP completions installed in the ACG Field. Installing multiple Screen PBR to provide baffling against crossflow is a novel concept. This technique does not compromise gravel pack quality or sand control integrity. The success seen with this technique makes a compelling case to further develop the concept on a larger scale in ACG and maximize field recovery.
Miscible Water Alternating Gas Injection WAG Field Scale Application in Algeria: An Effective Way to Improve Oil Recovery, Rejuvenate Mature Field and Develop Opportunities to Stream Gas Sales
Authors: Allal M. A. , Brancolini A. , Smail F. , Kaaroud Z. , Kriat M. A. , Elmutardi M.
Published: October 2023

Water alternating gas (WAG) injection technology is methods which may improve oil recovery efficiency by combining the effects from two traditional techniques—water and gas flooding. Both microscopic oil displacement and sweep efficiency can be enhanced by WAG implementation (Surguchev et al. 1992). WAG injection consists of injecting water and gas from the same injection wells which contribute to the improvement of overall sweep efficiency by:
Implementation First of a Kind Edge Computing Solution to Increase Production and Reduce Emissions at Bakken and Permian Unconventional Basins
Authors: Baaren S. G. , Sharma R. R.
Published: October 2023

There is a need to reduce carbon emissions sources at production facilities, which can be addressed by employing a digital solution that optimizes the facility's operational set-points in real-time. A novel software solution was developed which can operate on a cost-effective controller at a facility. The software uses many process variables already monitored at a facility to accurately model variables that are not measured, such as the Reid Vapor Pressure (RVP). The software also computes optimized set points, such as the minimum oil temperature required to meet the RVP of the final product.

The novel digital system was installed at one facility in the Bakken and two facilities in the Permian. At the first facility (Bakken), the temperature was optimized using an air cooler. At the second and third facilities in the Permian, the temperature was optimized using heaters. The temperature was optimized to minimize emissions and maximize oil shrinkage whilst ensuring that the RVP would not exceed a specified value required for custody transfer.

It was found that the initial model needed calibration at all three sites. The model was calibrated using oil samples that were processed with an analyzer. The calibration method applied was API MPMS 4.2 Appendix C, whereafter the RVP predictions consistently were within a ± 0.5 psi delta compared to values measured with a sample analyzer.

Once the system successfully optimized the oil temperature in the Bakken, the tank vapor combustion and oil shrinkage reduced by 40% and 0.7%, respectively. The oil temperature was successfully optimized using the heater at the second facility (Permian West), resulting in a 72% reduction of heater emissions, 28% reduction of tank vapor combustion and 0.5% reduction of oil shrinkage. At the third facility (Permian East), heater emissions were reduced by 77%, tank vapor combustion reduced with 40% and oil shrinkage reduced by 1.7%.

The field trials prove that the system can be implemented successfully without cyber-security issues. The relatively low implementation cost combined with reduced oil shrinkage results in an attractive return on investment and a negative cost of carbon abatement. In other words, implementing the system is profitable whilst carbon emissions are reduced at the same time, yielding an attractive business case.
Addressing Asset Integrity, Strongly Emphasizing Energy Efficiency & Sustainability
Authors: Awadhi Ibrahim Al , Sharma Ashok , Subramaniam Krishnan
Published: October 2023

Objective/Scope (25 – 75 word)

Existing Fired heaters in Ruwais Train-1/2 are designed and constructed in 1980 and are currently running with low efficiency of ~76%. In addition, fin burning is observed, due to high fin temperature which impairs heaters performance and necessitates replacement. This paper portrays the specific engineering way adopted to revive the performance, improve efficiency & enhance integrity of the existing 40 years old fired heaters.

Methods, Procedures, Process (75 – 100 word)

Replacing convection section was identified as opportunity to improve & maximize value. Adopting systematic engineering approach, three options (identical, full and partial replacement) were evaluated and best option with maximum benefit was selected as below. Improved tube fin density: Optimum selection of fin density is very crucial not to increase the heater draft at the same time to obtain maximum heat recovery.Enhanced fin material: Existing tube / fins are replaced with CS tubes & 11/13 Cr fins to sustain high temperature & avoid fin burning.Install future tube rows: 2 future tube row space were installed with fin tubes, enhancing heat recovery and reducing flue gas temperature.

Results, Observations & Conclusions (100 – 200 words)

Thermal design of the heaters confirmed that following enhancements could be realized upon existing heaters upgrade. Support Sustainability by reduction in fuel gas consumption and flue gas emissions by 8 to 10%Efficiency increases as below. Heaters 1 A & B - Increase from 76.4 to 86.1%Heaters 2 A & B - increase from 77 to 86%Heaters 3 A & B - Increase from 73 to 84 %Flue gas temperature leaving the convection section drops down from 460 to 263OC in heater 1 & 527 to 300OC in heater 2.Estimated Reduction in CO2 emission is ~ 54,000 MT/year.Integrity: Enhance integrity and service life of convection section by use of improved convection section tube material and improved tube fin material 11/13 Cr for selected rows.Foundation: No impact on foundation as increase in weight of the heater <1%Performance: Proposed new convection section design enables the furnace to be operated at its design duty by avoiding burning of fins with use of enhance fin material.Profitability: Cost savings of USD 39.5M for a design life of 15 years for 4 heaters due to reduction in fuel gas

Novel/Additive Information (25 – 75 words)

Strengthening the aging facilities is crucial to ensure its integrity, life extension and facility performance. However, the benefits are doubled when the asset life extension actions are resulting in enhancement of efficiency, performance & cost saving for the extended life.

Asset life extension can earn to operating companies, when escorted with smart enhancements supported by latest technics and careful selections.
Overcome Parted Sucker Rod in Artificial Lift Sucker Rod Pump Without Fishing Operation in Pendopo Oil Field
Authors: Arifien R Nova Rifika , Putra Mario Aditya Haris , Rasyid Muhammad , Kuncoro Anang Arie , _ Sucipto , Khair Utuh
Published: October 2023

Sucker rod pumping systems are widely used in oil wells. The frequent issue of sucker rod pump is parted sucker rod while operated due to lifetime and workload. Parted sucker rod causes pump off, the pump unable to lift the liquid from the subsurface to the surface, hence causing loss of production. The fishing tool that commonly used to catch the sucker rod fish is overshot or mousetrap. Fishing operation causes rig cost and operating time increase. This paper presents a solution in the operation of reproducing wells with parted sucker rod problem without having to do fishing job.

Using parts from sucker rod pumps designed and modified to overcome the problem of catching and connecting parted SR bodies of various sizes, without having to pull out the sucker rod string and replace parted sucker rod or fishing job. This tool has a different catching design compared to the existing tools, such as overshot. The dies are designed to increase flexibility during engaging operation, therefore there is no require to change the dies to catch multiple size of fish.

This innovation succeeded in accelerating and increasing the effectiveness of well services operation because without having to do fishing job, resulting in reducing non-productive time and costs. This tool has been used at the Pendopo Field, South Sumatra, Indonesia since the end of 2021 until now, for example in West Benakat Structure with 286 Days (27 March 2023) the well is still producing. The benefits obtained from this tool lead to efficiency in well services operations are saving rig operating costs for well maintenance of USD 20,000 per well, saving rig operating costs and reducing lost production opportunities of more than USD 212,000 during 2022, as well as reducing the potential for work accidents
Case Study of Multilaterals Drilling in Under-Balanced Coiled Tubing Drilling (UBCTD) Implementation and Challenges for the First Time in Operator Group of Companies
Authors: Osama Mohamed , Sumaida Ali Sulaiman Bin , El Shahat Ayman , Al Mutawa Ahmed , Almazrouei Saeed , Saleh Abdalla , Yousfi Fawad Zain , Almteiri Nama Ali , Baslaib Mohamed , Mantilla Alfonso , Deshmukh Rohit V. , Solaiman Tarek , Abdulsallam Fouad , Ladmia Abdelhak , Rangel Pedro , Rennox John , Cui Shuai , Jumagaliyev Yerlan , Basha Maged
Published: October 2023

Under Balanced Coiled Tubing Drilling technologies is well proven technology that has been piloted for the first time in OPERATOR for Gas sour Reservoirs this being the first time in the OPERATOR Group of Companies, (UBCTD) technology has proven to be able to enhance the production rate greatly compare with conventional overbalanced technique. However, the UBCTD technology has a limit on the lateral length due to buckling and lock up of the coiled-tubing string. Multilateral drilling can overcome this limit and allow wells drilled by UBCTD technology have a comparable total lateral length with the conventional ERD wells.

Detailed planning was carried out for the technology implementation there were many challenges in the operations, nevertheless, this is the first project of it is kind on the company, the lessons gained from daily challenging operation considered the stepping stone of the technology implementation in Abu Dhabi.

This paper shall spotlight on the project challenges and learnings gained from well to another and how it helps to improve the well performance.

The technique for multilateral drilling is characterized according to definitions established in 1997 during the Technology Advancement of Multilaterals (TAML) Forum held in Aberdeen. These standards classify junctions as TAML Level 1, 2, 3, 4, 5, or 6 based on mechanical complexity, connectivity, and hydraulic isolation. In UBCTD wells, the most common multilateral technology is with TAML level 1, which is done by open-hole sidetracks with barefoot completion.

Plan set to perform the two open hole sidetracks from the main lateral hole to examine the UBCTD multilateral design philosophy for the first time using UBCTD technology and drill a multilateral well with 3 laterals, each of the lateral lengths around 4,000 ft. Comprehensive planning and simulations were done to overcome the challenge of different reservoir pressure, wellbore instability and open-hole sidetrack operations. The sidetrack and multilateral well were proved to be successful with flawless drilling without any NPT and greatly enhanced production of the well.

No doubt that coiled tubing under the balanced technology pilot was extremely successful in all aspects, the paper shall describe all challenges and mitigations in addition spotlight on the best practice of planning and drilling a multilateral well in UBCTD during the execution phase and how it is impacted on project wells delivery. Body text 2 paragraphs.
Rapid Digital Oilfield Transformation Using Edge Computing and AI
Authors: Shukla S. , Hassan K. , Elsiwi A. , Bosnina S. , Saeed N. , Fannir J. , El-meshri A. , Gamberrato A. , Haddad J.
Published: October 2023

The timing and quality of operational decisions are critical factor in preventing production shortfalls and ensure sustained high level of operational efficiency. This impact of these factors amplifies multiple folds if the operations are in remote fields. Edge computing applications have surfaced as a powerful tool to ensure the right decisions are taken at the right time and by the right people. The paper describes multiple innovative and novel applications of edge computing and machine learning deployed in a remote field with no connectivity to enable peak well and network performance by efficiency improvement of artificial lift system, accurate virtual flow metering, minimize HSE exposure and simultaneously reduce the carbon footprint of the operation.

New wells have been drilled in the green field located in western part of Libya. The field is a remote area with no digital connectivity yet and some of the wells require ESP to sustain production. The remoteness of the field also caused potential asset security concerns for the generators and ESP surface system (VSD).

A holistic production performance enhancement digital solution package including sensors, solar power and satellite connectivity was deployed in the field centered around an edge computing platform to develop a digital twin of the green field with multiple wells. Virtual flow metering was done for all the wells using different techniques depending on the well architecture. Well models were run on the edge for wells with ESPs to estimate flow rates in realtime, while robust choke models based on well head and line pressure data were used to derive highly accurate well flowrates. The edge computing device was connected to ESP and the data gathered was analyzed in real time at the edge to identify ESP underperformance and detect any anomalies. At the same time machine learned algorithm continuously analyzed the video captured by two strategically positioned cameras to detect any potential intrusion by person or vehicles.

It is estimated that apart from the significant production performance gain the solution has reduced 16 metric ton of carbon footprint on an annual basis associated with this operation.

The solution allowed for rapid digitization of the field and early realization of value at a relatively much lower capex investment than traditional digital oil field solutions with an opex based model.
Towards Greener Hvac Refrigerant Usage For Offshore and Onshore Facilities -Petronas Journey in Managing Refrigerant in its Production Facilities
Authors: Basri H , Ekhwan A
Published: October 2023

Petronas currently operate 3,226 units of HVAC system to support its production facilities for its Upstream facilities. The HVAC systems are used to provide the required ventilation for shelters during emergency situations, ensuring required humidity for climate control for sensitive electronic equipment, and provide cooling for human comfort. Out of the 3,226 units currently under Petronas Upstream, 915 units are with R22 refrigerant, while the rest are a mixture of other refrigerants such as R134a and R407c. This paper explains about Petronas’ strategy in managing its refrigerant changeout program, to comply with Kigali Amendment to Montreal Protocol, to gradually reduce the consumption and production of hydrochlorofluorocarbons (HCFCs), moving to a more environmentally friendly refrigerants such as Hydrofluorocarbons (HFCs). This is to be achieved and tracked by developing a 10-year road map, from 2020 to 2030, to clearly indicate to stakeholders on key milestones for this initiative. Appropriate Key Performance Indicators have been developed to ensure key activities are tracked and monitored. 3 main methods to achieve the goal of 100% elimination of HCFC usafe in Petronas Upstream facilities are;

Situational Assessment of HVAC inventories in Petronas facilities, focusing on units with HCFC Execution of identified action items including refrigerant retrofit guideline, changeout strategy and manpower competency program Continuous tracking, monitoring and improvement of the action items

Key action items identified and included in the 10 years road-map are

Refurbishment and rejuvenation of old HVAC units from HCFC to HFC Retrofitting suitable HVAC units HCFC to HFC Stocking up of R22 (HCFC) refrigerants to ensure uninterrupted operations.

These 3 key action items are critical to ensure Petronas able to optimize cost as well as complying to the plans that was made. Beyond 2030, Petronas is looking for alternative refrigerants such as hydrofluoroolefin, which have a lesser Ozone Depletion Potential (ODP), and Global Warming Potential (GWP). This however, may require higher Capital Expenditure (CAPEX) investments, as well as adjustments to Operational Expenditure (OPEX)
Leveraging Real Time Operational Data to Reduce Greenhouse Gas Emissions
Authors: Guzman Juan Sebastian , Fuenmayor-Gonzalez Douglas , Turrel Benjamin , Dauce Lucas
Published: October 2023

This paper aims to share the journey of Carbon Footprint reduction in Exploration and Production (E&P) in reducing carbon emissions on operated assets through the implementation of a Real-Time tool for Monitoring Green House Gases (GHG) Emissions and Energy Efficiency (EE). The objectives are to improve the processes efficiencies, track and aid to reduce the total emissions. The solution was designed to monitor GHG key sources using available real time data within facilities. It starts by tracking emissions coming from energy usage through fuel gas combustion and then addresses emissions resulting from energy loss, such as flaring, venting and liquid fuels. The tool has been successfully deployed across 34 operated sites, allowing the tracking of approximately 85% of GHG emissions from Scope 1 & 2 within the E&P Operated Assets’ perimeter.

The implemented solution follows a highly standardized and scalable approach. A model is built once and then applied to hundreds of equipment and assets. Once deployed, the model continuously provides real-time data derived from calculations, analyses, and Key Performance Indicator (KPIs). These products increase operational efficiency and help decision-making process regarding emissions reduction. Additionally, transparency and traceability are ensured by granting users access to all data and calculation.

The tool uses different inputs such as fluid composition, process design data and operating parameters. It delivers a comprehensive overview of emissions and performance, ranging from individual equipment to site and country levels. The solution also eases benchmarking carbon footprint in different systems and identifies corrective and mitigation actions for both design and operational philosophy. Furthermore, it allows to establish a relationship between GHG and Energy efficiency based on potential optimization to be carried-out on significant energy users.

Headquarters and operating centers consistently rely on the solution's displays, which present performance indicators for daily discussions and used in operational decision-making. This solution enables operators to identify poorly performing equipment and capture undesired process deviations as well as metering inaccuracies that contribute to GHG emissions. As a result, these indicators improve operational excellence and revenues, while minimizing the environmental impact of our activities.

The paper discusses the implementation process, highlights the capabilities of the digital tool, and demonstrates its value through use cases where a positive impact both GHG reduction and improved energy efficiency was measured. By leveraging existing resources and valorizing field data and software, we have successfully transformed our operational practices and brought them to higher standards in terms of environmental performance and lower carbon intensity.
An Alternative Coiled Tubing Solution to Access Isolated Reserves Below Two Ball Valves in the Columbus Basin of Trinidad & Tobago
Authors: Mammadli R. , Adilov R. , Ramkissoon A. , Hosein N. , Friedli J. , Holder D.
Published: October 2023

The Well A in the Columbus basin of Trinidad & Tobago was completed with a dual selective Cased Hole Gravel Pack. The completion included two ball valves and multiple sliding sleeves to isolate zone A from zone B. At the end of the completion phase, multiple wireline attempts were made to shift open the two ball valves without success. The well was put on production from the upper Zone A only while lower Zone B was isolated with two closed ball valves. This scope was to open the two ball valves to regain access to the reserves in Zone B and to isolate Zone A by closing the sliding sleeves.

After numerous wireline attempts to gain access to Zone A via electricline clean out, shifting, and milling tools, coil tubing was selected as an alternate conveyance method to shift close sliding sleeves and open both ball valves. The attempt to close the sliding sleeve and shift open the ball valve with coiled tubing was unsuccessful. The decision was to mill the ball valve with differential pressure creating upward force on milling BHA when milling the ball valves.

The initial attempt to close the sliding sleeves with coiled tubing was unsuccessful with one sleeve remaining in communication with Zone A. The top ball valve was milled successfully with a 2.65" tapered bit in ∼4.5 hrs and drifted successfully multiple times using the same toolstring. Pressure behavior confirmed that the bottom ball valve remained fully closed. A 2.5" bit was then run and milled on for ∼8 hrs. with no further progress. A second run was made with a new tapered 2.5" bit and successfully gained access to Zone B. The size of the milled hole estimated on the bottom valve was 1.76". Analysis revealed that the 1.76" restriction at the bottom valve would allow the well to produce at its full well capacity. After successfully gaining access to Zone B, the open sliding sleeve in Zone A was isolated with a straddle packer.

The unique achievement was to mill two closed ball valves as part of a single operation. Being unable to shift close a Zone A sliding sleeve created cross-flow conditions in the well throughout the milling of the bottom ball valve. This introduced challenges to run through the milled top ball valve and progress the milling of the second ball valve with differential pressure. As a result, the second ball valve was milled partially, and the straddle packer was installed across the Zone A leaking sliding sleeve with the cross flow. Therefore, this job was a unique experience in the field that had important leanings that are applicable across the industry.
From Field Trial to Full-Scale Deployment of Pulse Waterflooding on Mature Oil Fields. Incremental Oil at No Cost
Authors: Adil Mukanov
Published: October 2023

Pulse or cyclic waterflooding is a well-known technique to optimize water injection schematics, that requires virtually neither capital nor operational expenditures. Therefore, it is very attractive for marginally mature oil fields to stabilize and even boost oil production with the aim of improving economics. So, the paper demonstrates successful case studies from the South-Turgai Basin in Kazakhstan.

Pulse waterflooding was implemented by increasing the injection volumes of one group of injectors and choking or shutting down another, thereby, sending periodic pulses in a sandstone formation. The pulses created translate into a fast pressure drop in high permeability and a slow pressure drop in low layers, causing a pressure differential and fluid crossflow. So, it was designed for stratified heterogeneous reservoirs, where we couldn't properly displace oil from poor zones. The theory was put into practice in the KK field trial area, and unexpectedly, we achieved profound improvements in production performance. Thus, the next step was to upscale the activity on other sites.

As a result of the first trial, more than 150 Mbbl of oil increment was obtained. That was promising, and the second field went through the same procedure. Pulse waterflooding was applied to the north and south parts, divided by the extensive gas cap of the A field. Most producers in both parts exhibit a clear trend of not only stabilization but also gradual growth. That was mainly reached due to an increase in fluid rates and no changes or event reduction in watercut. Previously, the average oil rate in the south had steadily declined at a 26% annual rate, but after that, it increased for the first time in 10 years. A similar picture is observed in the north, where a 22% annual decline turned into a rate stabilization and then increase. Eventually, the total oil increment is 21 400 tons or 166 Mbbl.

Pulse waterflooding proved to be an efficient EOR technique. If wisely applied, waterflooding optimization by playing with rates of injection patterns can lead to considerable sweep efficiency and, in turn, recovery factor. Finally, the most critical aspect of this story is that 166 Mbbl of oil increment costs zero for the operating company. That becomes the best option in terms of economics and the extension of fields’ lives.
Buoyancy Technology Used to Successfully Install Casing in Argentina's Longest Extended Reach Slim Well Pad
Authors: Bahl C. , Tait W. , Garcia S. , Munawar M.
Published: October 2023

The main objective of this paper is to summarize and present the results of extended reach casing installations in the Vaca Muerta basin in Argentina. The wellbores used as case studies in this paper had lateral lengths up to 4250m and includes the longest lateral cased in the Vaca Muerta region. A discussion of the operational parameters, placement philosophies and a risk assessment will be covered.

A glass disc flotation collar was installed as part of the casing string. This device traps air between it and the float equipment, reducing the frictional forces acting on the casing through the buoyancy effect. At the target depth, a pre-determined pressure is applied to the glass disc, rupturing the disc and allowing circulation in preparation for the cementing operation to follow.

Previous papers such as Rastegar et al. (2018), introduced the concept of placing the flotation collar at an "optimal" location. These previous attempts all assumed that the optimal position was the location that yielded the maximum hookload possible at target depth. While this is often the case, an alternative approach was taken in this case study whereby the flotation collar was placed to maximum the hookload at the build and curve section of the wellbore where frictional forces are often of highest concern.

Operation decisions that impact flotation collar effectiveness are also discussed in this paper. The primary discussion point is centered around the mud filling strategy used and improvements implemented at the rig. A discussion of the early filling strategy used, and the improvements made for the case study will be covered in detail.

The results of the case study project determined that there was a 28% reduction in the run-in-hole time when using the new deployment strategies. These strategies also reduced the need for string rotation, ultimately reducing casing wear and fatigue.
Drilling and Completing of Highly Depleted and Unconsolidated Sand Requiring Overbalance Mud Weight for Shale Layer. A Control Made Possible with Strong Well Planning Optimization and Mechanical Earth Model Iteration
Authors: Ninga M. Chembou , Ponte G. , Rouat T. , Murray P. , Ozioko R. C. , Bois A. , Oredolapo O.
Published: October 2023

Cameroon, Rio del Rey basin has been developed in the late 70's with more than 400 wells drilled & producing from different reservoirs in vertically (stacked reservoir) and horizontally (faulted) compartmentalized fields. The long production history of these fields coupled with the under-compaction state of some deep geological formation tends to raise a real challenge to any operator which would plan to drill infill wells in this context to sustain the production rate.

The addition of any drainage points in currently producing reservoirs must pass through in-depth analysis of the current state of stress in the drilled zone. One must consider the under compaction of shale layers requiring high MW to counteract the collapse pressure, the huge depletion of the targeted reservoir and the need to maintain a minimum overbalance in front of unproduced layers at virgin pore pressure. The resulting narrow margin between pore pressure & collapse pressure on the low end, and the fracture propagation and initiation pressure in the higher end, can drive to non drillability of the wells planned. However, thanks to thorough trajectory optimization - mainly well inclination angle at the entry of reservoir section - and iteration supported by a solid 1D Mechanical Earth Model (MEM), it was possible to drill two sidetracks (ESM-1ST & ESM-2ST) in this challenging environment, with up to 3000psi overbalance in front of severely depleted permeable formations, completed by a cemented 5½″ liner in 6¾″ open hole. It was possible to validate the possibility to enlarge drilling envelope by increasing the fracture pressure thanks to inclination and even being able to operate beyond this limit thanks to strong wellbore strengthening procedure implemented. Improvement process through lessons learnt from the first sidetrack helped to drill and case off the second sidetrack well successfully.
Capability Development of Technician in Oil and Gas Operation: A Story of PETRONAS Upstream Business in Revolutionizing Competency Development in Meeting the Aspiration for the Field of the Future
Authors: Hussain Mohamad Hafez , Idrus Hana Maslinda Md
Published: October 2023

The objective of the paper is to share on PETRONAS Upstream (Upstream) journey in the development of technicians in meeting the business demands in volatile Oil & Gas industry. Being at the "Front Line" their competency & effectiveness in ensuring high uptime and reduction of unplanned production deferment will directly translate to meeting the Production Outputs and Business delivery. The competency of technicians is revolutionized through upskilling of current and future technicians to be Multiskilled.

The development consists of structured capability program, which encompasses the learning of knowledge and skill to ensure technicians are fundamentally equipped with proactive & predictive mindset. This is done through e-Learning process for knowledge and the ‘On-The-Job’ training exposure at the worksites (offshore and terminals) for honing their skills in the multi-disciplinary areas of Production, Instrument, Mechanical and Electrical. To ensure the learning outcomes for knowledge and skill in the multi-disciplinary areas are met, a structured knowledge and ‘On-site’ assessment is carried out. This is to ensure technicians can carry out their role in the multi-disciplinary areas safely and correctly.

PETRONAS Upstream journey in multiskilling of technicians started in 1998, with the introduction of the ‘Second Skill’. In 2018, the organization revolutionized the multiskilling program with the introduction of the ‘Third’ and ‘Fourth’ skill for technicians. We are also utilizing our very own Technical Training Centre, INSTEP to train these technicians.

Further to that, to ensure that the multi-disciplinary role of technicians who have mastered the four skills set and being utilized accordingly, the remodeling of required Production and Maintenance task listed through the introduction of Competency Level Indicators (CLI) for all listed Production and Maintenance task and the merging of task into multi-disciplinary task. With the new multi-disciplinary task, it is shown that there will be a significant increase in Operation Efficiency up to 25%. This can be translated into a manpower efficiency for manning of every Offshore and Terminal facilities and promote the concept of ‘do more with less’.

With the introduction of multiskilling, PETRONAS Upstream ambition of managing operating cost, particular in a low oil price situation, and managing increased cost of aging facilities will be realized and to remain competitive in all eventualities of possible volatility of the Oil & Gas price.
Data Analytics Driven Subsurface Reservoir Sectorization Review of a Giant Abu Dhabi Onshore Field Carbonate Reservoir for Efficient Reservoir Management
Authors: Javid Khalid , Alshkeili Sara , Al-Hammadi Fatema , Benourkhou Noureddine , Al Sayari Saleh Ali , Kenawy Maher , Ryzhov Sergey
Published: October 2023

This paper discusses the approach used to sectorize mature giant carbonate reservoir located onshore Abu Dhabi for the purpose of reservoir management, offtake, and injection balancing. The reservoir is developed under line-drive WAG scheme in combination with peripheral water injection. Future development plan for the reservoir includes massive deployment of Maximum Reservoir Contact (MRC) horizontal wells and a gas-based EOR scheme.

A practical data-driven approach, based on one of the ADNOC's Integrated Reservoir Management (IRM) workflows was selected for the purpose of sectorization. It starts from defining a number of possible sectorization schemes and goes through the review of:

relevant geological data (faults and structural features, rock properties and facies distribution), well performance data (productivity/injectivity indices, WCT and GOR mapping, WOR/GOR vs. cum oil trends, well maturity indicators), reservoir performance indicators (fluid properties and reservoir pressure distribution, water, and gas front movement, streamline analysis and analysis of injection allocation factors). compliance to the future development plans.

Through the review each of the preliminary sectorization schemes are scored for their compliance to IRM requirements and the scheme with the highest score is selected for the future implementation.

Out of eight sectorization schemes proposed at the start, one single scheme compliant with most of the requirements of ADNOC IRM workflow was selected. This scheme honors major faults and lineaments, reflects observed variation in rock properties and pressure distribution and at the same time caters for the requirements of future development schemes.

Selected sectorization scheme features five sectors, each having comparable number of wells, while number of wells "sharing" multiple sectors was reduced to the minimum. Being compliant to the distribution of reservoir pressure and to observed trends in well performance selected sectorization allows improved monitoring and management of voidage replacement, pressure maintenance and will cater for adequate surveillance planning and execution. Moving forward, selected sectorization scheme will be used for regular sector performance reviews aiming at identifying subsurface opportunities and areas of improvement and helping to drive efficient reservoir management decisions.