bluuebunny/crossref_metadata_2025 huggingface dataset:
FDP Simulation Studies for Green Fields Cluster Development in Less than 30 Days Utilizing Cloud Technologies
Authors: Papapetrou Georghios Dorou , Chuen Chia Pei , Mahamad Mohd Nur Adzizie , Md Rabi Ros Aliza , Seah Yong Han
Published: October 2022

BD Cluster green fields development located offshore Sabah, Malaysia, consists of three multi-stacked turbidite fields, namely A, B and C, encompassing thick and thin bed sands. Due to the lack of existing infrastructure in close proximity, a wellhead platform (WHP) will be installed on top of Field A. Fields B and C will be developed with a respective 8 and 7km subsea tie back to this WHP. Gas will be exported from the WHP to Facility-1 situated 5km away, whereas oil from a single thin oil rim reservoir in Field A will be exported to Facility-2 50km away.

The challenges faced by the Reservoir Engineering (RE) Team was delivering an extensive number of dynamic simulations while adhering to the Field Development Planning (FDP) submission deadline: 1) uncertainty analysis and probabilistic modelling for 9 models, 2) construction of coupled reservoir models 3) screening alternative oil and gas export routes, and 4) optimizing capex phasing by determining the optimum startup sequence of the fields. Delivering the FDP work on time with the limited software licenses and computing infrastructure available on-premise appeared to be a "bridge too far".

The limitations were addressed by PETRONAS LiveFDP digital transformation initiative commenced in 2019, through deployment of digital cloud technologies and solutions with scalable High-Performance Computing (HPC) environment. A total of 9 geological models were delivered to REs for dynamic simulation studies. Probabilistic modelling was then employed to obtain the dynamic P10, P50 and P90 models for each field. The Reservoir Coupling facility and Extended Network option were used in the numerical simulator to couple the standalone models in order to honor the overall facility constraints and incorporate the pipeline effects. Utilizing the coupled network model, multiple studies including condensate banking, determining optimum field sequencing and export route scenario were performed.

The FDP subsurface development simulation runs were completed within 1 month using HPC cloud solutions and workflows compared to 9 months if using on-premise infrastructure. It provided the necessary tools to allow the team: 1) accurately assess the impact of condensate banking on well productivity, 2) executed over 1200 cases for probabilistic modelling for the 9 models in 24 hours of simulation time, 3) reduced the number of wells derived from a previous study from 14 to 9 yielding a saving of ~US$115 million, 4) ~US$50 million savings as a result of capex phasing by optimizing the field start up sequence, and 5) US$130 million savings by establishing the lowest cost oil and gas export route scenario.
An Intelligent Approach to Predict Minimum Miscibility Pressure of Injected CO2-Oil System in Miscible Gas Flooding
Authors: Haider Ghulam , Khan Muhammad Arqam , Ali Faizan , Nadeem Ayesha , Abbasi Faiq Azhar
Published: October 2022

ANN Model was developed utilizing experimentally determined MMP data of 201 reservoir oil and CO2 injected gas. The data bank was randomly divided into training (70%) and testing parts (30%). The conventional statistical measures like coefficient of determination (R2), root mean square error (RMSE) and mean absolute error (MAE) were used to evaluate the predictive efficiency of the model and correlation. Cross-plot of predicted values versus the predicted data was also made to examine the accuracy of developed model. All the important parameters that affect MMP were considered in developing ANN model. These parameters include reservoir temperature, reservoir oil compositions and properties of heptane plus and composition of N2, C1, H2S in the injected CO2 gas stream. The results showed that developed correlation and ANN model can predict the MMP value with high R2, low RMSE and low MAE. The values of R2, RMSE and MAE are 0.9469, 218.7832 and 175.8902 respectively for testing data points. The presented technique can be used to provide an estimate of the MMP in the absence of experimental data and should be utilized in the initial screening of CO2 miscible flooding process. A novel correlation using artificial neural network (ANN) to predict MMP has been developed in this study. The MMP plays an important role in designing the miscible gas flooding processes and to plan appropriate surface injection facilities. MMP is traditionally measured through experimental and non-experimental techniques. The experimental methods are expensive and time consuming and results from currently used correlations vary significantly and hence there is need of reliable, easy and fast prediction technique.
Machine Learning for Prediction of CO2 Foam Flooding Performance
Authors: Khan Mohammad Rasheed , Kalam Shams , Abu-khamsin Sidqi A. , Asad Abdul
Published: October 2022

In a move towards development of sustainable and efficient hydrocarbon production, the industry looks forward to the deployment of carbon neutral and even carbon negative solutions. Accordingly, CO2 EOR is a viable option to improve recovery and has been applied in mature fields for over four decades. The downsides of poor sweep efficiency linked to viscous fingering and gravity segregation can be sorted through generation of CO2 foams in the reservoir. This work proposes the utilization of machine learning techniques, to predict foam flood performance which will thereby aid in optimization of laboratory core-flood experiments.

This work is based upon consumption of large set of existing laboratory data collected from literature, amounting to more than 200 data points. The dataset reports core oil recovery factor as a function of three reservoir parameters including porosity, permeability, initial oil saturation. While injected foam volume and total pore volume are also considered. Furthermore, the data records contain experiments for various foaming agent types which are catered for during the machine learning model development through the implementation of numerical tags. The input data is then divided in training subset for development of XGBoost model, complemented by integration of exhaustive grid search and k-fold cross validation techniques. Subsequently, the testing subset is reserved to measure efficacy of the developed model. The model development process involves tuning of machine learning algorithm hyperparameters which control the resultant accuracy, while at the same time it is ensured that the issue of model overfitting is avoided. Testing of the established model is carried out through an array of statistical measures including the R2 and RMSE values.

The proposed model is compared with actual experimental data. The machine learning model can achieve high accuracy in predictive mode for the output parameters. Through statistical error analysis performance measurement, it is observed that the machine learning model can predict CO2 foam flood performance with high R2 of around 0.99 and low errors. The excellent accuracy of the XGBoost model is credited to the complex processing involved with intelligent algorithms that can discover underlying relationships among the input variables.
Encouraging Chemical EOR Field Results: First Multi-Well ASP Flooding Pilot Project in a Carbonate Reservoir Worldwide
Authors: Al-Murayri Mohammed Taha , Sulaiman Dawood S. , Hassan Abrahim Abdelgadir , Al-Ajmi Naser A. , Thery Bastien , Maillon Remi , Nesbit Jimmy , Pitts Malcolm John , Dean Elio , Skeans Elii , Dean Robert Matthew , Britton Chris James
Published: October 2022

Alkaline-Surfactant-Polymer Flooding (ASP) has the potential to unlock massive oil reserves in quest of production sustenance within the bounds of profitable economics. Field results from a successful ASP pilot targeting the massive Sabriyah Mauddud (SAMA) reservoir in Kuwait, using a regular five-spot with five acre-spacing are encouraging. Oil cut post softened water pre-flushing reached 0% and tracer data indicated pre-mature breakthrough at the central producer. This necessitated in-depth conformance gel treatment1-3 to induce flow under matrix conditions and softened water injection resumed thereafter for a period of ~3 months, during which oil cut ranged between 2 to 6%. Oil cut then decreased to 0% again, beyond which polymer pre-flushing was introduced for a period of ~2 months, during which oil cut was increased to up to ~4%. ASP flooding resulted in an unambiguous and sustainable increase in oil cut with an average of ~12% over a period of more than 6 months. Furthermore, daily oil production rate after ASP flooding more than doubled. Effective oil-water separation of produced emulsion has been established and maintained using fit-for-purpose pre-heating, chemical dosing and gravity segregation technologies, thus resulting in relatively low BS&W levels in separated oil (i.e., <5%). Potential in-situ scale risks were effectively managed by injection an innovative scale inhibition package composed of inhibited glacial acetic acid in conjunction with a phosphonate-polymeric scale inhibitor into the capillary tubing string of the central producer, during which 100% production uptime was achieved for several months3. Field data demonstrated that in-situ scale risks due to ASP injection were originally overstated because scale issues were limited even without injecting the adopted scale inhibition package. ASP reservoir simulation forecasts indicate that oil rates and oil cut should continue to increase. ASP flooding is ongoing to date and continues to generate important operational learnings and priceless field data to evaluate the techno-economic viability of phased ASP flooding commercial development.
Coupling of a Reservoir Simulator with Geochemistry for Chemical Enhanced Oil Recovery
Authors: Limaluka Angelo Kennedy Lino , Elakneswaran Yogarajah
Published: October 2022

Chemical enhanced oil recovery (CEOR) techniques are some of the most effective and economical tertiary oil extraction processes. As a key tool for the recovery performance evaluation, reservoir simulation plays an instrumental role in the expansion of the field application of CEOR. However, their framework models essentially the physical aspect of the recovery process. The significant influence of geochemical interactions on the recovery performance remains largely unintegrated. In this study, MATLAB Reservoir Simulation Toolbox (MRST) was coupled with PHREEQC for improved modeling and simulation of polymer flooding and low salinity water flooding (LSWF). The MRST’s polymer model was extended for multi-phase chemical transport by the addition of chemical species in wells boundary conditions, and phase relative permeabilities were modified to account for the wettability alteration effect of the flooding process. In validation, the coupled model showed a good match against PHREEQC in a simulation of a single-phase carbonate core low salinity water flooding (LSWF). It also validated well in the case of matching high salinity experimental results. A demonstrative application of the coupled model in the simulation of LSWF showed 27% maximum incremental oil recovery with a 3.3 mean water-oil ratio (WOR). Furthermore, combining LSWF with polymer flooding achieved the same recovery potential but with much lower water production (0.2 WOR) and doubled production period. These results preliminarily indicate that polymer flooding and LSWF could be combined for at least 27% additional original oil in place (OOIP) recovery with no more than 1 WOR in carbonate reservoirs. However, as this recovery performance evaluation was done in 1D, further work on the coupled model includes improving it for multi-dimensional application.
An Enhanced Integrated Asset Model for Offshore Field Development Strategy
Authors: Azzarone Eleonora , Rossi Roberto , Cirillo Giovanni , Micheletti Giacomo
Published: October 2022

The derivation of an optimised field development strategy is one of the most important tasks in the oil and gas industry. Modern workflows apply complex integrated asset models (IAM) where reservoir and production network simulators are coupled to provide a single model of the entire asset. In this paper we present the solutions adopted to build an IAM for an asset in the current producing scenario, but also modelling future incremental surface facilities’ upgrades, tasks found to be beyond the capabilities of current commercial IAM products.

The asset consists of a number of oil and gas fields producing into a common network. A variable gas offtake through existing and future facilities is expected in the field development. Commercial IAM solutions cannot model this or update the constraint on the total production based on the changing offtake volumes. These limitations have been solved by a set of custom scripts embedded in the simulators. The scripts manage the inline separator efficiency both in the current scenario and also when a volume of the produced gas will be sent to the LNG plant planned in the asset future development.

The two configurations, i.e., the current producing scenario and the future development one, are based on the same set of reservoir models with different network schemes and facilities’ constraints. The integration of the reservoir and the network enables the determination of the impact of the facilities’ upgrades, namely the installation of a process unit close to the oil production platform and the routing of a fraction of the gas to feed an LNG plant under construction. The total production is increased because of the reduction of the backpressure due to the new location of the process unit and the reduction of the gas flowing to the current treatment terminal. The average gain both in the oil and gas production rates is around 20% for 5 years. Moreover, due to the unique flexibility of the IAM solution, additional projects (such as further developments to the existing producing reservoirs or tie-in of other fields already discovered) can be easily added to the model to simulate the future asset production.

For the particular asset being studied, a solution to the challenging reservoir-network coupling issue was developed employing a set of simulation scripts (including Python ones) that enable the modelling of the network configuration in a rigorous way. This approach overcame the current commercial application limitations and expanded the functionalities of each simulator included in the IAM.
Smart Nano Clay to Reduce Water-Based Mud Filter Cake
Authors: Abdul Latif Ummi Alia , Khairul Ikhwan Chong Zuhayra Nasrin Chong , Belhaj Hadi , Al Hameli Fatima
Published: October 2022

Encountering mud cake is a natural consequence of the drilling operation in oil and gas wells. Thick mud cake requires extra drilling efforts to remove it. Thick cake increases filter loss, reduces wellbore space and causes the drill pipe to be prone to get stuck. This study aims at enhancing the performance of the water-based bentonite by using drilling mud hydrophilic, smart nano clay to modify the rheological properties and reduce the thickness of the mud cake. Hydrophilic, smart nano clay is used to enhance water-based mud performance. The content of the bentonite is varied between 2% to 8% by weight of water and the temperature is varied between 25°C to 85°C. The nano clay particle size is increased by 1% starting from 12 to 20 nm in order to modify the rheological properties and, hence reduce the cake. The samples are hydrated, and their pH is adjusted. Viscometer FANN 35SA is used to measure the rheological properties of all samples under standard conditions. The thickness of the cake is measured using MITUTOYO Vernier Caliper. As a matter of fact, by using the nanoparticle water-based mud, it can reduce the mud cake thickness by approximately 56.25%. However, the filtrate volume surprisingly increased by 89% as compared to the collected volume with ordinary clay, determinant coefficients for the base fluid and nanofluid were found at 87% and 96%, respectively, which are close to the best-fitted lines. The average base fluid and nanofluid were found at 0.23657 and 0.12225 inches, respectively. The standard deviation of the base fluid is 0.08229, indicating that approximately 8.2% of the base fluid's data points deviate from the mean. The value of the nanofluid is 0.02363, indicating that approximately 82 percent of the base fluid's data points deviate from the average value. When compared to normal clay, the rheological characteristics, gel strength, and filtrate volume of nano clay illustrated a negative influence on drilling fluid performance and deviate from the API standard specifications. The values for PV, YP and gel strength indicate a high slope trend, however, the filtrate volume collected shows a decreasing slope trend. Results prove that the proposed nanoparticle water-based mud is successful and has reduced the cake thickness by nearly half compared to the ordinary clay. The Hydrophilic smart nano clay introduced here is a new technology. Resources of the material are available in nature and can be obtained with ease and low cost. This investigation outcome is based on solid experimental results and can be implemented in the field without extra efforts or the need for scale-up.
Nano Technology Micro-Emulsion Technology Removed Invert Emulsion Fluid Filter Cake Damage After Delayed Action Across Sandstone Reservoir
Authors: Olivares Tulio Daniel , Al-Zahrani Walid , Latter Kreke , Mukoro Temu
Published: October 2022

The objective of this manuscript is to present the value addition of a Nano Technology based Windsor IV Micro-Emulsion which helped to remove Invert Emulsion Fluid (IEF) filter cake across sandstones reservoirs. Benefits such as delayed reaction, uniform treatment across the reservoir, no losses or well control events and improvements in the well producibility expectations will be presented in this paper.

The approach was to determine the nature of the filter cake and determine an improved process for removing the cake from the well-bore utilizing a Nano Technology based Windsor IV Micro-Emulsion that will solubilize the filter cake through the creation of Micellar Structures in the 2-14 nanometer range. A series of laboratory tests were conducted to ensure compatibility with the formation, compatibility with formation fluid, along with the removal of the filter cake using the new chemical application process. The ICD screens were deployed and filter cake was removed with a minimum delay of one hour to prevent needless losses that could end up with catastrophic well control situations or excessive non-productive time trying to cure the losses to continue with the completions operations

The new chemical blend was mixed and deployed on well A & well B, under capable filter cake removal engineer and using the existing rig equipment with no operational issues. Both wells retained intact filter cake for at least a 2-hours period, thereby preventing initial losses and avoiding an LCM pill being pumped to cure the losses, that could result in formation damage or affect the permeability of the production formation. As demonstrated in the laboratory tests, full filter cake removal was achieved in a 12-24 hours period. In wells A & B, we did not experience losses within the time period required to run the upper completion and close the isolation safety valves. The conclusion from the field application is that this Nano Technology based Windsor IV Micro-Emulsion demonstrated the ability to remove the IEF Filter Cake in a controlled manner, allowing the drilling rig completion operations to be run without any interference or additional steps and after the soak period the wells A & B were opened to show improved Productivity Index post application.

The drilling-petroleum industry is continuously looking for technologies to improve the return of investment and maximize the wells producibility, definitely the introduction of this new Nano Technology based Windsor IV Micro-Emulsion package to the area of IEF Filter Cake removal will bring benefits and value to this purpose as was demonstrated after the implementation on wells A & B in the studied area.
First Industrial High Power Laser Field Deployment: Lab to Field
Authors: Batarseh Sameeh I. , Mutairi Saad M. , SanRoman Damian P. , Assiri Wisam J.
Published: October 2022

This paper presents the industry's first successful high-power laser field deployment and the strategy that led to this success, including lab-to-field transformation. This paper will also give an overview of the intensive research conducted over the past two decades, recent field deployment and plan forward.

Laser technology is used widely in almost every industry, from medical to the military, due to its unique features, such as precision, reliability, control and accuracy. The oil and gas industry capitalized on low-power laser applications such as sensing and measurements, but high-power laser applications remained beyond the realm of upstream. The program described in this paper aims to resolve it. To reach this goal, a strategic plan was designed around four pillars: laser-rock interaction, optomechanical design, energy delivery, and sustainability. The first pillar focused on developing a comprehensive experimental database of laser-rock interactions, which included tests on all types of rocks under different conditions. The second and third pillars concentrated on tool development and energy transmission via optical fibers. The last element analyzed how high-power laser applications enable sustainability in subsurface applications. The result is a comprehensive experimental database with thousands of tests and a robust field unit that can withstand harsh field environments. The system's design is enclosed, providing a safe and risk-free operation. The system consists of a laser energy generator, nitrogen tank, vacuum truck and tool.

The success of the intensive research conducted over the past two decades led to the development of the first high-power laser system for field applications and unlocked several upcoming applications.

All rock types have been successfully tested under different conditions, including in-situ tests in liquid and gas environments. The experimental plan was designed systematically and divided into phases, from fundamentals to advanced. Prototype tools were designed, tested, and upscale for field deployment. The tools combined optical and mechanical components. Several iterations, modifications, and improvements to the tools were applied until the optimized version was achieved. The laser source generates the laser beam (energy) at the surface. The power is transmitted via protected and shielded fiber-optic cables to the downhole tool, which is designed to control the geometry of the beam. High-power laser technology has been proven to effectively penetrate and drill in all types of rocks regardless of their strength and composition

High-power laser technology is an innovative alternative to current methods such as perforation, descaling and drilling. It is cost-effective, compact and environmentally friendly, providing sustainable operations. The advantage of the technology is that several applications can be performed with a single energy source (the laser), and only the tool needs to be changed for different applications.
Metal Expandable Packers Deliver Cement Assurance for Improved Well Integrity
Authors: Hazel Paul Roderic , Wallach Mathieu , Adeniyi Dapo
Published: October 2022

Operators globally are consistently challenged to deliver effective cement sealing for Zonal Isolation (ZI) between reservoir units and to prevent Sustained Annulus Pressure (SAP). This paper discusses such a challenge for a land well drilled in West Africa and how these challenges were addressed. The challenge was to achieve effective ZI of a depleted sand gas reservoir and provide B annulus isolation to prevent future SAP. The challenges arose from a combination of losses (during drilling and cementing) and potential gas invasion into the cement during the cement curing process. The solution utilized three Metal Expandable Packer(s) (MEP), two of which were expanded within wet cement. The MEP purpose is to deliver ZI Cement Assurance (CA) across the reservoir and one MEP set above Top of Cement (TOC) within the Open Hole (OH) to protect the B annulus from (SAP). Both solutions improved the overall well integrity, providing mitigation from cross flow, early water production and the risk of methane emissions release into the atmosphere.
Single Slurry Modification to Improve Well Integrity in NEB Field
Authors: Mahesa Widi , Alsaadi Alhanoof Musabah
Published: October 2022

Based on the history of cementation of 9-5/8″ heavy casing design in NEB field, all the wells are cemented with lead (10.0 ppg – 12.7 ppg) and tail (15.8 ppg), where during the cementation pure cement is gained in surface. Based on the Cement log, the lower area (Tail) is accepted and some discrepancies in the interpretation on the upper section due to tools limited capability in reading light weight cement and presence of dual casings. However, several years after the completion some of the wells have been identified as SAP B (Sustain Annulus Pressure) between annulus 9-5/8″ casing and 13-3/8″ casing.

An advance logging tools was run to one of the recent SAP B wells, that used integrated approach to do interpretation that considers the data from 3-dimensional acoustic sensors, cement bond logs, production data, open hole data logs and recent well operations. The interpretation is most likely scenario for this SAP B is micro-debonding of 9-5/8″ casing to cement which is causing the gas flow to surface; and cement failure below 13-3/8″ shoe with the source of SAP B is in Fiqa formation, while all the formations below Fiqa are acoustically quiet and no annular flow is happening from deeper reservoirs.

As per standard practice, in such situation the SAP B must be cured prior to re-complete the wells. To cure the SAP B, section milled across aquifer (RUS and Dammam) will be performed, followed by plug and squeeze across the milled section and later will be run with 7″ tie back cementation to surface. Performing these steps will require minimum 5 days prior to re-run completion string.

To improve well integrity in annulus between 9-5/8″ casing and 13-3/8″ casing, a dependable barrier for long term well integrity should be provided. A novel approach involving single cement slurry modification with expansion properties was discussed by adding post set crystalline material into cement design and tailored it to have expansion effect to minimize micro debonding and micro channeling. In parallel, maintaining slurry fluid loss properties is also critical to provide better cement bond. By changing the cement design into single slurry, the potential of losses will rise during cementation and might end up with poor zonal isolation in the annulus. Other aspect taking part as consideration is by using adequate spacer volume with engineered rheological properties for better cleaning, maximize both centralization and pump rate since pipe movement (rotation and/or reciprocation) is not an option.

The job was planned to be performed in single stage cementation, with maximize the centralization profile, use sufficient volume of spacer, then followed with pumping single slurry expandable considering adequate excess of open hole and displacing with maximum rate using the rig pump for better displacement efficiency.
High Fluid Loss Squeeze and Reticulated Foam Lost Circulation Material LCM Plugs 40,000 Microns Lab Simulated Fracture/Vug Opening
Authors: Savari Sharath , Butcher Jacques , Al Hulail Mustafa
Published: October 2022

Controlling severe to total lost circulation in naturally fractured/vugular formations has always been challenging, especially in carbonate formations across the Middle East. In these environments, conventional particulate lost circulation materials (LCMs) may not be effective due to the uncertainty regarding fracture and vug sizes. This paper presents an extension to previous work on a high fluid loss squeeze (HFLS) and reticulated foam LCM, providing further technical justification for implementing this technology to cure severe to total lost circulation events.

An earlier paper presented laboratory evaluation methodology, test results, and field application of the subject HFLS and reticulated foam LCM. At the time, laboratory test data was presented for an LCM combination that could seal a laboratory simulated fracture size of 9,800 microns.

In the current work, a similar laboratory test set up was used to evaluate the efficiency of this LCM combination to seal larger size openings. An adapter with an opening size of 40,000 microns (1.57 inch/4 cm), was used and the combination of HFLS and reticulated foam LCM successfully sealed the opening when tested using an industry standard test set up. The LCM combination was also weighted with barite to determine if the sealing performance was consistent for anticipated applications.

The LCM plug formed in the test set up was evaluated for the maximum differential pressure it could withstand in wet conditions, as well as its compressive strength. Under wet conditions, the plug withheld 4,000 psi differential pressure and yielded a compressive strength in the range of 3,170 psi to 4335 psi in duplicate tests. The plugs were also analyzed using CT scanners to visualize the alignment of foam and the particles within the plug. The additional test data supports a more detailed assessment of the LCM combination for specific applications prior to deployment.

The results of this extensive laboratory testing on a combination of HFLS, and reticulated foam LCM demonstrates the potential of such materials for reducing or curing severe to total lost circulation events in naturally fractured/vugular formations. The test data presented in this work is the first to be reported in the petroleum industry literature for any comparable LCM at 40,000 microns fracture/slot size.

The most notable advantages of improved LCM technology are the increased control of hydrostatic pressure in the well bore by minimizing fluid losses downhole as well as a reduction in well construction costs through decreased rig time associated with lost circulation.
New Generation of Environmentally Friendly Nanoshale Inhibitor Water-Based Drilling Fluids
Authors: Alqahtani Hassan Sakar , Al-Arfaj Mohammed Khaled , Alhasseni Mohammed Faisal , Alotaibi Mohammed Abdullah
Published: October 2022

Environmentally friendly Mesoporous Silica Nanoparticles (MSNs) has been used for the first time as a Nanoshale inhibitors in water-Based Drilling Fluids. Nanoshale inhibitors used in this study eliminate the use of toxic high potassium chloride (KCl) concentration in shale drilling operations and reduce the waste management associated cost with drilling fluid treatment and disposal.

The dispersion test of MCM41 Nanoshale inhibitor with Silurian shale samples revealed to be an effective candidate with significant interaction reduction between the drilling fluids and the shale particles. This new Nanoshale inhibitor maintains the integrity of the cuttings and minimize the interaction of fluids with shale sections during the rolling test. XRD patterns has been conducted to determine the crystalline structure of shale and nanomaterial samples.

Although the application of nanomaterials to improve the performance of conventional water-based drilling fluid was studied by researchers, it is the novelty of this research to eliminate use of KCl and to develop the new generation of Nanoshale water-based drilling fluid with economical consideration and lower environmental impact.
Innovative Fluid Technology Enhanced Wellbore Integrity, Optimizing Casing Sections in the Bandurria Sur Field in Argentina
Authors: Cejas Martin , Juaristi Jose Manuel , Hedegaard Allan Claus , Maldonado Reinaldo
Published: October 2022

In the Neuquen Basin in Argentina, the Bandurria Field is notorious for its narrow operational window, which is caused by the difference in pressure gradients between formations. This environment often demands the use of managed pressure drilling (MPD) technology in addition to a robust well design, with several planned sections, and can substantially increase the cost of well construction. To extend the pressure-gradient operative window, the operator opted for a new drilling fluids-focused technology and operational strategy which reduced the number of casing sections. The ultimate objective of the operator was to construct a productive and cost-effective well, while maintaining wellbore stability between challenging formations.

Using a break-even price objective of just over 40 USD/bbl, a strategy the operator adopted was the use of an ultra-resistant and flexible fluid technology in the open hole section, using a technology engineered within the drilling fluid system to ensure that newly drilled rock was rapidly sealed and protected enabling to work with the same drilling fluid density two different formation pressures. Using this technique, the operator executed a successful operation, expanding the operating window and limiting wellbore instability while drilling into the two problematic formations.

With the use of MPD, offset wells on the same pad presented significant operational challenges, including wellbore instability from stuck pipe, sidetracks, and lost circulation of the drilling fluid. The implemented technology and technique, referred to as a Fluid Stabilization Additive (FSA), allowed the operator to perform a dynamic formation integrity test (DFIT) while drilling through the transition zone to evaluate the magnitude of the operative window increase and compare the results to offset wells on the same pad. The Fluid Stabilization Additive enabled a 1-2 lb/gal increase beyond the fracture gradient window, which was observed in the field.

The FSA was used in additional wells drilled in the same formation, which resulted in a considerable improvement in the drilling efficiency when compared to offset wells. Another economic advantage for the operator was the savings of oil-based drilling fluid (OBM) that was utilized for each well. Drilling fluid savings, and the prevention of lost mud to the formation minimized the total cost of the drilling fluid and helped to maximize the efficiency of the drilling operations.

Finally, a comprehensive laboratory evaluation was conducted to compare the efficacy of this unique approach. The Bandurria Sur Field was drilled at a much lower cost as a result of the FSA and modification to the drilling fluid formulation.
Removing the Requirement for Deburr Runs on a Field Development Multizones Well Completion
Authors: Jamieson Kyle Ivar , Cayao Joven John Ravelo , Hazel Paul Roderic , Prasad Bala , Ibitomihi Sunday Michael , Kolakalapudi Madan Kumar , Thomson Stewart James
Published: October 2022

A Metal Expandable Packer (MEP) as an Inner String Packer (ISP) that has the capability to run through multiple perforated zones, without the need for a deburr run was qualified for a BSP oil & gas field development in Brunei. Four injectors and four producers will be developed across a stacked sand shale sequence, requiring zonal isolation (ZI) and flow control to maximize production. The inclusion of this MEP technology provides a robust life-of-well Cased Hole (CH) sealing system with inherent anchoring and removes the deburr run, reducing associated rig time and cost.

Initial design for Shell Whale proved the sealing capability of the MEP after passing through a non-deburred 9-5/8″ perforated liner. The BSP well design and qualification required an MEP to pass through a 7″ cemented and perforated liner deployed on a 3-½" inner string comprising up to six zones – each zone with a mechanical sliding sleeve and control line for zonal Permanent Dowhole Pressure-Temperature Gauges (PDHG).

Job planning was conducted to configure the MEP, PDHG and SSD to minimize the erosion risks and maximise the perforation interval. Maximum use of onshore sub-assembly and SIT was identified to improve offshore rig-up efficiency.

BSP identified the worst-case load scenario with the MEP anchoring against the ID of the 7″ liner due to thermal, hydraulic, and ballooning effects by performing Wellcat simulation. Based on this simulation, the MEP product was successfully qualified in accordance with ISO 14310 V3 (and subsequent V0) including the load envelope.

Thorough FEA modelling validated the design, expansion and sealing capabilities, and demonstrated that a burr height of 0.17″ generated damage within the seal will be closed and sealed post expansion. Following the FEA, a rigorous ISO 14310 qualification was completed.

An estimated overall NPV improvement for the field development within the first two years compared to alternative swellable-type products, and the elimination of a further 2 days/well rig time (approximate) during well construction compared with a mechanical-type packer.

Further application of the MEP on multi-zone completions will enhance the ZI (sealing) of the 7″ to 8 ½" rock face (cement assurance or cement replacement) and may ultimately lead to the multi zone completion deployed within the open hole (OH) delivering further substantial cost reduction.
Beyond the Known Coiled Tubing Limits, First Coiled Tubing Intervention in a 40,000+ ft Well in the UAE: An Outlook of Downhole Tools Technology, Testing and Special Equipment Deployment to Successfully Accomplish the Project Objectives
Authors: Ottolina Renny , Ambrosi Giuseppe , Tuoyo Ella , Veronesi Miguel , Jimenez Jose , Al Marzooqi Abdulmohsen , Shbeb Yaman , Al Ali Salim , Al Braik Haitham , Humoudi Hassan Obaid , Correia Gladwin
Published: October 2022

Objectives/Scope: The latest developments in well construction demand equipment that defies the current industry limits to access the full length of the pay zones in 40,000+ ft wells. With the growing trend of drilling horizontal wells in the mega reach category and beyond, there is a need for a new level of engineering design of Coiled Tubing (CT) strings and downhole technology with a specific approach to reach these new and expanding requirements.

Methods, Procedures, Process: Extended reach conveyance of CT is a challenge that service companies and operators have progressively addressed as wells are drilled deeper into the mega reach area. Advanced CT string designs and materials, as well as systematic variations of parameters affecting friction coefficients between CT and wellbore completions, provide benefits to operators in extending the reach of the horizontal sections. Special downhole tools and engineering testing are required to plan the best outcome from the available downhole force technology to increase wellbore coverage while maintaining well underbalance, reducing operational footprint, and safely deploying the heaviest 40,000 ft 2-3/8 in CT pipe offshore.

Results, Observations, Conclusions: This paper describes the systematic process used to address the mega reach challenges, as CT is required to reach Total Depth (TD) in wells longer than 40,000 ft in one offshore oil field in Abu Dhabi. It summarizes the considerations taken to design the right string for the project and describes the multiple technologies used to extend the reach of the CT in the horizontal sections while remaining underbalanced. Additionally, this paper discusses the implementation of a surfactant-based Friction Reducer (FR) system to extend the CT reach and the friction matching analysis performed while calculating the extended lock-up depth. In addition, the special transportation solutions to deploy the CT reel to the wellhead are discussed, along with the track stack required to make these operations possible.

Novel/Additive Information: Detailed data collected throughout the campaign enabled the operating company and the service company to benchmark the results of the operations, drawing better conclusions well after well and enabling a positive loop of improvement leading to economic gains as the campaign was executed.

Technical challenges, downhole tools, and fluid solutions to reach TD Transportation solutions for mega reach CT string deployment
Extending the Performance of Standalone Sand Screens (SAS) with Flow Segmentizers in Gas Wells
Authors: Shaffee Siti Nur Amira , Ghazali Hasyimah , Rajan Preveen Kumar , Wan Mohamad Wan Amni , Thant Maung Maung Myo , Bakar M Farris
Published: October 2022

Sand control application in gas wells is very challenging, especially in the application of a standalone sand screen (SAS) due to the high erosional risks. Many failures have been observed in the industry over the years causing production deferments and additional OPEX to the operators for remedial sand control operations. This work presents the performance evaluation of a unique SAS in open hole completion concept piloted in a horizontal gas well and the replication in other new wells in a Malaysian gas field.

In 2012, a pilot gas well was completed with SAS with optimally placed flow segmentizers along the horizontal completion to limit the screen erosional risks. The placement was determined using a tool developed through an R&D. It estimates the optimum locations of the flow segmentizers based on the targeted SAS life or erosional velocity limit imposed. At the heart of it is a proprietary erosion model specifically developed for SAS application. The well performance was compared to adjacent wells producing from the same reservoir but completed using the conventional open-hole gravel pack.

The pilot well achieved higher Productivity Index in comparison to the adjacent wells. Over the 10-year observation period, the production performance was consistent with minimal skin values and no sand production issues. Multifinger Imaging Tool (MIT) was run to measure the erosion levels in the tubing and the result indicated very minimal erosion because of sand production even after several years of production. Recently, another one (1) new infill well was drilled and completed with the same concept as the pilot well. The segmentizer placements were supported by an optimization study based on the expected production scenario. Positive flow back results with no indication of sand production was detected from the intrusive sand monitoring equipment. With the application of SAS and flow segmentizers, a cost reduction of 25% as compared to more complex application of open-hole gravel pack was realized.
Unlocking the Potential of Twin-Screw Multiphase Pumps: Field Applications, Performance Simulation, and Recent Challenges with Case Study
Authors: Abdalla Mohamed Gamal Mohamed , Ali Ramzi
Published: October 2022

Over the past decades, the term -artificial lift- has mainly referred to the conventional techniques of downhole pumping (e.g., electrical submersible, sucker rod, progressing cavity, others) and gas lift. Today, a more comprehensive definition is becoming evident, a definition which matches all the major changes happening in the oil & gas industry. Accordingly, artificial lift is not limited to techniques conducted in the wellbore; instead, techniques used throughout the whole production system to "lift" the produced fluids towards their final destination are included.

All petroleum wells’ production lives are brought to an end when the downhole reservoir pressure cannot deliver fluids traveling up to the processing facility due to high flowline pressure. Numerous technological approaches were practically implemented at many fields, approaching the end of their lives, to extend the field exploitation. One such technique is to introduce Multiphase Pumps to add energy to the unprocessed crude at the wellhead to transport oil / gas / water mixture to the Central Processing Facility (CPF) -without the need for preliminary separation or well interventions, to install downhole equipment- while maintaining an environmentally friendly performance as gas flaring is no longer required and oil spills are avoided. This paper aims at addressing the difficulties in the evaluation of multiphase Pumps; especially those handling high gas volume fraction (GVF). These problems are related to uncertainty about the approach adopted to test the pump. Minimal information about the multiphase pump performance leads to difficulty for any new pump model to evaluate its applicability as the performance curve of the pump is dependent on the inlet fluid properties, such as fluid inlet pressure, temperature, water cut, GVF, etc. Therefore, the correct prediction requires the evaluation of the pump performance for each change in fluid properties.

The results of this study clearly demonstrate the tremendous effect of multiphase pumps in reactivating dying wells and enhancing production from brown fields providing a cost effective solution rather than conventional methods. Some operation challenges are very important to be considered especially when operating the pump at high GVF as a liquid recirculation system is required coupled with precise evaluation of system operational parameters to avoid gas flashing within the pump leading to reduction of pump efficiency. As well, solids handling measures upstream of the pump are essential to enhance the integrity of the system. This systematic, transformative research aims at improving our understanding of multiphase pumping and optimizing the operation parameters of Twin-screw pumps through data-driven models and field experiences leading to production optimization and sustainable future profitability.
Sedimentology and Diagenesis and Their influence on the Reservoir Quality: A Case Study of the Late Cenomanian Mishrif Formation, Western Region, Abu Dhabi
Authors: Phukan Madhujya L , Siddiqi Saad A , Alshehyari Shamma , Mansour Bashar , Alshehhi Maryam , Shashanka Ashis , Guangcheng Hu
Published: October 2022

The Cenomanian-early Turonian Mishrif Formation is an important reservoir rock throughout the Middle East. Although extensive studies have been carried out on the Mishrif Formation across the Middle East, very limited information is available about the Mishrif Formation from the western region of Abu Dhabi. The primary objective of this study is to review the sedimentology of the Mishrif Formation in the oilfields of the western region of Abu Dhabi and to define the petrology, the depositional and diagenetic history, and the reservoir quality.

The Mishrif Formation is sedimentologically characterized using an industry-standard lithofacies classification scheme. Subsequent sedimentological interpretations define the depositional evolution of the sediments. Petrologic assessment highlights the depositional texture and successive diagenetic alterations that have affected the sediments, thereby modifying the reservoir properties.

The Mishrif sediments represent deposition on a carbonate ramp system modified by a potential barrier shoal, along with localized relief developing shoal-like geobodies. A broad range of lithofacies represent the range from wackestone to boundstones, with the sediments interpreted to represent deposition in a shoal complex through backshoal and rudist buildups to a distal mid-ramp to an outer ramp setting. A petrographic study reveals multiple diagenetic phases have affected the sediments. Porosity is enhanced considerably due to multiple leaching phases, which are followed by subsequent cementing phases comprised of calcite and dolomite that degrades the porosity in places. Fracture events do not seem to have any significant impact towards enhancing the reservoir properties as they remain dominantly filled by cements but locally, a few fractures, which are open, contribute to enhancing the connectivity. A moderate to very good reservoir quality is inferred for the sediments of the Mishrif Formation. The porosity values range between 7% to 34% and permeability values from 0.06mD to >10 D. Interrogation of the core analysis data indicates a depositional control along with a diagenetic influence on the reservoir quality.

This study helps to resolve the complexities associated with the sedimentological makeup and diagenesis of the Mishrif Formation in the western region of Abu Dhabi. The understanding from this study will help in further works related to reservoir geomodelling and pattern prediction, which may also be extrapolated to uncored intervals for representativeness and regional correlation of the Mishrif Formation.