bluuebunny/crossref_metadata_2025 huggingface dataset:
Conventional Tight Gas Field Through Unconventional Eyes: Data Analytics Help to Optimize Fracture Design and Operations
Authors: Yuan Roger , Bahri Khalfan , Veeken Cornelis , Shoaibi Sultan
Published: March 2022

Deep tight gas fields in Northern Oman are often compared to and approached with unconventionals due to their tight matrix properties and the necessity of employing hydraulic fracturing to deliver productivity. Complicated by operational constraints and field histories, hydraulic fracture effectiveness – how fracture stimulation delivers relative to how much matrix flow contributes to production – remains a puzzle and a challenge. This further affects how to optimize existing completion and stimulation strategy in order to improve the value proposition.

In this study, we review the fracture and production performance of a mature gas field in Northern Oman. Integrating data of various technical disciplines, we re-examine a wealth of cumulative field data over two decades of operations with an aim to identify the key enablers for fracture placement and production. With integration of reservoir properties, geomechanics, and time-lapse production profiles, we identify that geomechanics plays a key role in controlling reservoir fraccability and the placement of hydraulic fractures. While hydraulic fracture containment within the Barik formation has been well recognized and considered a given in multi-staged fractured vertical wells, the creation of fracture heights is found dependent on the in-situ stress conditions and pumping metrics, which further links to productivity. Such inter-relationship could potentially be utilized to optimize fracture performance by a refined placement strategy.

With big data, the common technical opinions that normally arise from a deterministic approach on limited data can be better visualized and addressed. The statistical strength of the analysis leads to improved understanding of the subsurface complexity, interaction of reservoir quality with completion design, and a suite of future optimization opportunities.
Optimising Waterflood Performance in Mature Fields, Using Autonomous Inflow Control Valve Technology
Authors: Shihab Sufyan , Khadhuri Shaikhan , Saadi Hamoud , Aakre Haavard , Mathiesen Vidar
Published: March 2022

Managing increasing volumes of produced water is one of the main challenges faced in waterflood fields. Better water mobility -compared to oil-, results in increasing water cut (WC) and reduced oil production, with time. In Qarn Alam, with mature brown fields depleted through waterflooding, oil producers are completed as open-hole horizontal wells. This means well experience water breakthrough from day one, due to poor oil-to-water mobility ratio, toe-heel effect, permeability variations and matrix fractures. Inflow Control Devices (ICD) has demonstrated good efficiency in delaying water breakthrough, however, when breakthrough is a given factor, ICDs lose that efficiency. The Autonomous Inflow Control Valve (AICV®) is a novel powerful tool that helps reducing WC in favour of oil, based on contrasts in fluid viscosities. The tool has a movable piston that opens/closes autonomously -without any connection to surface-, to reduce the unwanted water production, where choking increases with increasing WC. AICV technology was deployed in several oil producers, in carbonate reservoir brown field. The field has produced for decades, and is facing an increasing water management challenge. AICV completions were designed such that wells are divided into compartments isolated by swellable packers. The comparison of historical production data without and with autonomous inflow shows clearly the benefit of installing autonomous inflow control. Preliminary assessment showed an average 75% reduction in water-cut and 20% average increase in oil rate.
What is the Best Artificial Intelligent Technology to Solve Drilling Challenges?
Authors: Gharbi Salem , Al Majed Abdul Azeez , Abdulraheem Abdulazeez , Patil Shirish , Elkatatny Salaheldin
Published: March 2022

Drilling operation started drilling more challenging wells that is farer, deeper and in unconventional conditions; this require the drilling industry to adopt new technologies supporting them in these challenges. One of the big potential supporting technologies is the artificial intelligent. Artificial intelligent could help drilling engineers and operation crew in crunching the massive amount of drilling data converting them to decision-like format, leading to safer, faster and more cost effective operations. The challenge is that artificial intelligent projects consists of multi dimension tasks, starting from data handling, infrastructure building, through model development and integrating with existing environment. Such tasks confuses even IT teams, so developing artificial intelligent projects targeting drilling domain will be very tough. Experience shows that a lot of oil & gas artificial intelligent projects fails due to miscommunication between the business domain experts and the artificial intelligent, not having common understanding, problem in the data, or model computability issues could be also other reason for such failure.

This paper propose a methodology that will increase the possibility of having success artificial intelligent drilling project. This methodology is CRISP-DM which stand for Cross Industry Standard Process for Data Mining. This methodology consist of the following phases Business Understanding, Data Understanding, Data Preparation, Modeling, Evaluation and Deployment. This paper is shading lights on these phases, also it will derive the readers through a drilling case-study, where this methodology was applied leading to successful artificial intelligent drilling project.
Evaluation of Inflow Control Device Effectiveness to Mitigate Thermally Induced Fractures in Injection Wells
Authors: Almarri Misfer
Published: March 2022

Injection of cold fluid is injected into hot reservoirs and rocks undergo contraction due to temperature difference. This contrast in temperatures causes the in-situ stress to reduce considerably. When the Minimum Horizontal Stress (σhmin) falls below the Bottomhole Pressure (BHP) due to temperature changes, fractures may initiate and/or propagate. Fractures resulted from thermal processes is referred as Thermally Induced Fractures (TIFs). TIFs can cause highly non-uniform distribution of the injected water flow in the wellbores, reduction in the sweep efficiency, and early water breakthrough in the nearby production wells. The objective of this paper is to evaluate the effectiveness of Inflow Control Device (ICD) to mitigate these fractures in water injection wells.

A real field history matched sector model with evidence of TIF occurrence is utilized in this paper using a 3D reservoir thermal simulator coupled with a 2D TIF model and a geomechanical model. The impact of different completions in injection well with TIF modelling under different scenarios is investigated.

The added value of ICD was quantified and proved to be effective in controlling TIF initiation and propagation as well as in improving the wellbore flow performance. The selected ICD size should be neither too big (no control) nor too small (over-restriction of injection rate).

TIFs mitigation method proposed in this paper is practical, efficient, and strongly contribute to the research aimed at improving waterflood performance in oil fields. Recommendations and guidelines can be utilized in waterflooding operations during modelling, designing, and planning stages.
Condensate Optimization Through Digital Tools
Authors: Al Farsi Ghaida , Jayawickramarajah Angeni
Published: March 2022

Khazzan, the gas giant in Oman, and its new gas processing facility were started up in 2017 delivering a daily contractual volume of gas o the local grid. The wells had high gas deliverability potential, and yet they were constrained to deliver the contractual volume specified by the commercial agreement with the government. To maximize the value of this excess gas potential, a new digital tool was utilized to optimize our condensate production – increasing production by 2-3% with no additional cost.

The first step was to create a digital twin of the asset, including the structure of the asset and the fluid dynamics of the flow regimes, temperatures and pressures. Historical data was used to populate the digital twin, and sensors in the asset were set up to send real time data to the functioning twin of the physical asset. Any constraints in the production system were built into the digital twin to provide the most accurate simulation. The tool was then used to monitor, simulate and optimize production, by testing multiple variables until an optimal solution was found for the entire production system from wells, through facilities, to export.

Significant value was obtained by utilizing the digital toolkit, delivering not only economic value but progressing innovation as well. Traditional production management requires considerable time to manually integrate the complex infrastructure and fluid dynamics. This digital twin of Khazzan enabled the work to be automated and completed much faster than conventional methods–allowing petroleum engineers to focus on evaluating well performance rather than running time-consuming scenarios of anticipated or likely events. The response time to any changes in gas nomination was also reduced significantly, by running simulations with a few clicks on the screen and updating them in the live streaming Wells Overview sheet.

Condensate optimization was not only achieved through maximizing condensate production, but there an opportunity was realized to minimize condensate flared volumes during plant upsets which ultimately impact recovered condensate. This was completed in conjunction with the live streaming Wells Overview – to capitalize on utilizing a digital workflow to reduce flaring volumes.

Overall, this digital twin benefited BP Oman by indicating where efficiencies can be improved and potential problems in the production system, leading to significant business value being added to the company.
Effective Reuse of the Produced Water - A Case Study from a Field in South Oman
Authors: Singh Jasbindra , Harthi Mohammed , Siyabi Mohamed , Al Salmi Marya , Hamm Carmen , Riyami Omar , Hatmi Safiya , Abdel Samiee Rady , Hinai Mohammed , Mazroui Anas , Sinani Yousuf , Mahruqi Issa , Al Azri Nasser
Published: March 2022

Produced water is an inextricable part of the hydrocarbon recovery processes, yet it is by far the largest volume waste stream associated with hydrocarbon recovery. In a C-field in South Oman, the produced water has been disposed in the aquifer zone of the producing formation. The feasibility of alternative ways to dispose water at surface using alternative options is being evaluated with the objective of reducing (or completely stopping) this water disposal which has shown benefits in maximizing the recovery by reversing the pressure decline. A simple model has been used to quantify the benefits of produced water re-injection into the deep aquifer zone.

Deep water disposal (DWD) has been on-going for over 20 years in the aquifer zone in the B-formation in this field in South Oman. All the produced water from the surrounding fields is sent for disposal near the field via the C-Field Processing Station DWD system. This DWD activity has provided important energy to the system as evident in the reversing reservoir pressure trend in field. However, due to various reasons, efforts are being put forward with the aim of replacing DWD with alternative ways of disposing produced water at surface.

An integrated model has been built and calibrated to the field response and used to predict the field performance. The calibrated model recommends to continue pressure to the field through water disposal or injection system. The study predicts the complete discontinuation of DWD will put significant reserves at risk eroding the field value and has quantified the amount of water available for the alternative options for surface disposal. The study has also identified an opportunity to further optimize the solution for pressure maintenance and thereby, potentially improving the recovery from the field.
Diverse Asphaltene Challenges in a Mature Field: A Fluid Study from Iraq
Authors: Jin Liping , Li Wenyong , Lu Yan , Liang Jiabo , Dong Jian'an , Wang Shouxin , Laaby Hussein Kadhim , Ammar Ali Jabbar , Ouda Tayih Ali , Muteer Raad , Muktadh Tammeem , Yongjun Fang , Tuck Jon , Khamatdinov Rafael , El-Ghazzar Ahmed , Harper Christopher
Published: March 2022

CNOOC Iraq Limited (CILB) operates the Missan oilfield in Iraq, which consists of three oilfields: Buzurgan oilfield, Abu Gharib oilfield and Fauqi oilfield. To maximize production from the field it has been necessary to overcome different challenges related to asphaltenes (tubing deposition, formation damage, emulsions) – firstly by properly understanding the fluid behaviour, and then by developing and implementing mitigation strategies.

To understand the asphaltene stability of the reservoir fluids, an isothermal depressurization study was performed on a monophasic bottomhole sample from the reservoir's main production unit.

Asphaltene Onset Pressures (AOPs) were identified and used for tuning an equation-of-state model to generate an asphaltene precipitation envelope (APE). Modelling software was used to calculate pressure-temperature profile of fluids both in the near wellbore region and production wells and determine if they entered the APE. This was reviewed against historical field data to assess if asphaltene issues were predictable.

Common fluid property screening tests (e.g. De Boer plots, Colloidal Instability Index) under-predicted the occurrence of asphaltene precipitation in the oilfields.

When fluid pressures and temperatures in the reservoir and well environment were compared against the modelled APE, they showed the reservoir fluids passing through the asphaltene instability region for most wells, indicating a risk of deposition in the tubing and in the formation.

Comparing predictions with field data highlighted that precipitation of asphaltenes does not always result in tubing deposition and additional factors such as watercut and oil viscosity need to be considered. Other fluid-related issues, such as stable emulsions and formation damage, have been observed in the field and require managing. Results from this study show that these can be explained in terms of asphaltene stability issues arising from fluid P/T behavior and interactions with water.

The importance of drawdown management, already practiced by the field operator, is shown to be a key tool for managing and controlling asphaltene issues. The value of optimizing solvent-based stimulations and retaining the ability to stimulate ESP-lifted wells is also demonstrated.

Measuring asphaltene stability using virgin reservoir samples, and applying fluid screening tests, are common activities during new field appraisals. The results inform high value decisions, ranging from completion design to reservoir management strategy.

This study, conducted on a mature field with known production history, shows how results from fluid characterisation studies relate to actual experience of asphaltenes during production. The use of fluid studies in diagnosis and treatment of operational challenges is also demonstrated.
Lessons Learned from Recent Post-Frac Drawdown-Buildup Tests in Tight Sands Reservoirs
Authors: Alshawaf Ali , Al Momen Mohammad , Khoja Ghaliah , Rabines Jaime , Al Doukhi Hassan , Issaka Mohammed
Published: March 2022

Developing tight sandstone across vast area requires proper data collection and analysis. Due to the tight nature and heterogeneity of these reservoirs, several vertical and horizontal wells need to be drilled and completed with multistage hydraulic fractures to assess their potential.

Initial post-frac flowback tests, in addition to long-term pressure build-ups, have already been conducted on several of the wells. Data Analysis have assisted in characterization of the tight hydrocarbon reservoirs and evaluating of hydraulic fracture geometry. The results have aided to investigate the drainage radius and well interference, to determine the optimal frac and well spacing design. These information are highly needed to build and calibrate single and full field dynamic models to estimate and address the uncertainty on the ultimate recovery and to come up with an optimized development strategy of the field. The paper presents findings and key lessons learned to efficiently design pressure build-up tests in tight sandstone reservoirs.
Optimizing Ongoing Field Scale Polymer Flood in South of Oman Through Detailed Simulation
Authors: Anand Adi , Riyami Omaira
Published: March 2022

Polymer flood (PF) applications have increasingly been extended to medium-to-heavy oil reservoirs for enhanced displacement and sweep efficiency and pushing the recovery beyond the limits of conventional recovery techniques. The relatively low carbon footprint and gas-light nature has made PF attractive in many cases compared to the traditional thermal methods. Consequently, many fields in the Sultanate of Oman with viscosities ranging from about 90cP to 500cP have been studied and field trialled for polymer development, and one such field has been successfully undergoing field-scale PF for over 8 years, which is the subject of this study.

As PF is matured in the field, the ongoing challenge is to support production operations and optimise flood performance.

This study lays the foundation for holistic simulation study targeting theoretical based considerations for PF optimization. It starts with understanding the nature of polymer/polymer and polymer/water type displacements and stabilities, and encompasses modelling the phenomena of viscous fingering/instabilities in a range of model set-ups, starting from high resolution core-scale 2D models to 3D sector models incorporating varying degrees of geological heterogeneities.

Understanding of displacement stability gained with high-resolution models is extended to investigate polymer/water mixing, Water-Alternating-Polymer (WAP) recovery and polymer grading (tapering). These subjects have been integrated to emphasise the optimal polymer slug size requirement with creaming curve analyses that build on the principles of containing fingers/instabilities due to lower viscosity follow-up slugs or chase water.

The polymer flood optimization is taken to the next step by investigating the concepts of polymer grading. Three prevalent grading concepts proposed by Claridge ([5], [6], [7], [8]), Ligthelm-Schulte and Stegemeier in combination with different mixing rules form the basis of polymer grading assessment.

The study highlights significant scope for optimizing polymer flood in the field both in terms of long-term improved recovery performance at reduced cost as well as tackling the short-term operational challenges, potentially impacting the business bottom-line.
Online Monitoring for Measuring the Viscosity of the Injected Fluids Containing Polymer in Chemical Eor
Authors: Jouenne Stephane , Heurteux Guillaume , Levache Bertrand
Published: March 2022

Viscosification of water with polymers is a mature technique used in different enhanced oil recovery processes (AP, ASP, SP and P flooding). The viscosity of the injected fluids is generally measured in the lab on solutions sampled manually at different locations of the polymer injection process. In order to increase the reliability of these measurements and to alleviate the quality control, there is a strong need for measuring online the viscosity.

On a field, polymer solutions can be highly degraded if they are sheared during the sampling or contaminated by the oxygen when exposed to the atmosphere during the viscosity measurement. Different procedures have been proposed in the industry to prevent or minimize degradation. However, routine measurements through manual sampling mobilize operators, take time and are often questionable. In this paper, we present three types of online viscometers developed for avoiding degradation during the sampling and the viscosity measurement. A fourth one enables to do reliable viscosity measurements in the lab.

A low pressure tank viscometer enables to measure continuously the viscosity of the polymer mother solution. This viscometer is particularly adapted to highly concentrated and viscous solutions since it is not sensitive to the presence of particles, gel debris and oil. Two high pressure viscometers can be connected at any point of the high pressure injection line (well head for example) to monitor continuously the viscosity of the injected polymer solution. Their low foot print make them easily transportable. Sensitivity and precision of these equipment were assessed through online measurements at the lab and pilot scale. They were found to perfectly match the viscosity measurements performed with lab rheometers even on pure water. A fourth lab viscometer was developed in order to improve the reliability and the robustness of classical viscometers used in operations. Measurement in anaerobic condition prevent any risk of oxidative degradation. All the viscometers are automated with a minimum need of human intervention.

All the developed rheometers are at the prototype stage. Particular attention was paid to the robustness of each element and its adequacy with field constraints. Field tests are now needed to finalize their development and assess their durability on the long term. The use of robust online viscosity measurements during EOR operations would allow effective continuous remote monitoring, greatly improving pilot interpretability and operability during pilot and commercial stages.
Improving Uptime of Sandy Wells with PCPs Through the Application of Self-Optimization Routines
Authors: Velazco-Quesada Conny , Vargas Luis , Sawafi Mohammed , Busaidi Adel , Mamari Hilal , Yahyai Ahmed , Woolsey Kelly , Montilla Benigno
Published: March 2022

A field trial has been completed in five oil producing wells, completed with progressive cavity pump (PCP) and under sand co-production scheme with the following objectives: Increasing well uptime by eliminating rotor stuck events and extending time between failures,Reducing locked-in potential associated to slow ramp-up process from initial to target offtake,Reducing the need for operator visits to start or adjust well running conditions after station trips,

To achieve this, four wells with very premature failures (less than 6-months) were selected for the trial. One fifth well with high level of depletion was also selected. The target for this last application was to check the impact of reducing fluid level safety factor on pump performance.

In all wells, PCP well controllers were installed with self-optimization routines that maintained safe fluid levels above the pump intake while adjusting speed for potential sand ingress. Speed ramp-up time was programmed for completion within two days of start up.

First, realtime signals were enhanced to monitor all well parameters that could affect performance, such as tubing head pressure (THP) and casing head pressure (CHP). This information was key to manage the actual fluid levels above the pump, even in gassy wells, allowing safety factors to be reduced by 50% without affecting pump performance.

Increase in pump run life by 40 to 140% was observed in the four sandy wells selected. No well interventions were required for sand flushing. Ramp-up time was successfully completed within a day of start-up and after two days production at target was stabilized.

After trips, it was found that the well started without the need for operators, as long as power supply was restored. Operator visits were only required for power or signal issues to be fixed, but well was safely kept optimized within those periods.

Estimated oil production availability increase from this trial is 12% per well per year.

This paper presents the main learnings from applying a self-optimization routine in 5 sandy wells and what is important to consider to achieve cost reduction, increase in well uptime and to reduce the need for manual adjustments/field visits.
Dimethyl Ether DME Solvent Based Enhanced-Oil-Recovery Technology - A Laboratory and Subsurface Study
Authors: Salimi Hamidreza , Ameri Amin , Nieuwerf Jan
Published: March 2022

DME as a water-soluble solvent for enhanced oil recovery has been introduced and some study results of DME enhanced waterflooding have recently been reported. However, DME-based EOR has not yet been implemented because of high prices of DME, the consequent need to recycle and reinject DME, and uncertain incremental oil per injected DME. This paper describes new insights into the different aspects (lab, subsurface, and economic) of DME-based EOR technology.

An experimental protocol was defined to study the IFT, viscosity, and density of DME-Oil-brine mixtures as a function of T, P, and salinity, and DME compatibility with heavy components (e.g., asphaltenes), and adsorption on minerals.

A compositional fractured-reservoir dynamic model that honors the PVT characteristics of DME was developed to investigate the performance of DME flood into fractured and unfractured reservoirs with light and heavy crudes.

A business case as a function of DME recycling efficiencies, incremental oil, and phase implementation was discussed.

The experimental results revealed that the oil viscosity 31 cP is significantly reduced to below 2 cP when mixed with DME in small volume ratios. No asphaltene precipitation (asphaltene content = 6.4 wt%) was observed when the oil was mixed with DME at increasing ratios up to 80 v/v%. Compatibility tests with formation water (total salinity 9.2 wt%) showed that DME is soluble in the formation water without any incompatibility or salting-out effect. The DME partitioning into oleic phase improves when temperature and brine-salinity increase. Imbibition tests at 5 bars and 50°C with DME-saturated formation water and limestone core plugs (permeability: 1.3–2.2 mD) increased the ultimate recovery to 70%.

The simulation results indicate that DME injection into unfractured reservoirs does not improve the displacement efficiency, but it accelerates oil production because of improved injectivity up to 30%. However, DME injection into heavy-oil fractured reservoirs can improve displacement efficiency initially by enhancing imbibition rates from the matrix to the fracture system. However, this improved displacement efficiency decreases as DME injection continues because of DME breakthrough and there will be a point at which the DME displacement efficiency becomes the same as water. Nonetheless, DME significantly increases the recovery factor from heavy-oil fractured reservoirs (up to 200%).

The economic results demonstrate that to have an economic DME-based EOR technology, the DME-recycling efficiency must be higher than 80%, incremental oil must be higher than 15%, and development must be a phased development plan.
Optimization of Sp Flooding Design Using Simulation Calibrated with Lab Core Flooding
Authors: Ahmed M. Elmuzafar , Sultan Abdullah
Published: March 2022

The development Chemical EOR technologies is increasing rapidly due to the massive need of hydrocarbons in the world and because most of the reservoirs have reached tertiary recovery phase. Carbonate reservoir have challenging conditions of high salinity and high temperature that affect the performance of SP flooding. In this paper, we are using a commertial simulator to optimize the design SP flooding in these harsh conditions, and use our previous core-flooding experiment to calibrate our simulation model.

The porosity distribution for the model was determined by using the micro-CT imaging which gave the distribution along the core. The permeability was calculated based on the porosity-permeability relationship from the real core data. The real surfactant and polymer properties were measured in the lab in terms of rheology and IFT. History matching of the base case to the real core data was performed using particle swarm optimization machine. The matching parameters were the critical capillary number for de-trapping for both low and high IFT flooding, besides the relative permeability curvature parameter. Many scenarios were investigated after having a match with 2.3 AAE.

The polymers used are a Thermo-Viscosifying Polymer (TVP) and an Acrylamido Tertiary Butyl Sulfonate (ATBS)/acrylamide (AM) copolymer. The surfactants are carboxybetaine based amphoteric surfactants SS-880 and SS-885. We did previous study to optimize the core-flooding design for SP flooding in the lab but we faced the problem of inconsistency. Because there are some factors that, we cannot control and keep them constant to compare results, like the core permeability and porosity and their distribution and mineralogy. The combination of surfactant and polymer in one slug gives more recovery than the injecting them individually. ATBS gave higher recovery than TVP. There is no difference in recovery due to changing the surfactants because their IFT is close to each other. The observation is that increasing the slug size will increase the recovery so we recommend using diminishing return economic analyses to determine the slug that gives the highest profit. Injecting SW-SP-SW is the best sequence among the other three sequences, taking the advantage of injecting longer slug of viscous fluid, as the increment due to IFT reduction is minor. The viscosity sensitivity study shows higher recovery with more viscous fluids so the limiting factor will be the economics and the pump capacity.

Optimizing the SP flooding design for carbonate reservoirs using simulation with the help of lab experiments results for calibration will decrease the uncertainty. This technique is better because you can control the fixed and variable parameters to know exactly the effect of individual ones.
Asset Integrity Management Through Lean Engineered Material Handling Study for Oil & Gas Processing Facilities on an Offshore Island Facility
Authors: Kannan Aravind , Saha Dip Narayan
Published: March 2022

Objectives/Scope

This paper details the implementation of lean engineering principles for formulating the material handling study at an Oil & Gas Onshore Island facility.

Methods, Procedures, Process

The paper analyses a case study at a major offshore island facility in the Abu Dhabi region, comparing the traditional methods followed in material handling with the proposed lean method of material handling. Principles of lean engineering such as simplification & standardization have been implemented to create a lean-approach. A key aspect of the lean philosophy is to incorporate a "Fit-for-purpose" design rather than an over design for material handling cases that the facility might never see in its 25-year lifetime.

Results, Observations, Conclusions

An offshore island brings several challenges with respect to material handling due to its location compared to an onshore facility because of the limited availability of traditional maintenance equipment like Mobile cranes. Following the lean method not only saves manhours while developing the material handling philosophy during the design phase of the project but also helps in lowering the procurement costs associated with the equipment required to aid material handling. This lean engineering approach, when applied to material handling study has resulted in the reduction of both CAPEX & OPEX cost for an offshore island facility. Standardizing the way material handling philosophies are developed in a project helped in improving the overall process efficiency, reducing errors, lowering the time taken for study, improving quality, and client satisfaction.

Novel/Additive Information

The novelty of the proposed material handling study model involves using lean engineering principles which are typically used in manufacturing/assembly lines in a study for maintenance of equipment on an offshore island.
Designing an Optimum Recipe for SP Flooding in Harsh Carbonate Reservoir Conditions High Temperature High Salinity
Authors: Ahmed M. Elmuzafar , Sultan Abdullah , AlSofi Abdulkareem , Al-Hashim Hasan
Published: March 2022

Chemical-Enhanced-Oil-Recovery (CEOR) processes have been used for increasing oil recoveries from oil reservoirs following the primary recovery phase. At harsh reservoir conditions (high salinity and high temperature), many CEOR methods fail to achieve their objectives. This raises the challenge to design optimum recipes that tolerate these harsh conditions and hence attain maximum hydrocarbon recovery at the minimum possible cost.

This paper evaluates the effectiveness of a Thermo-Viscosifying Polymer (TVP) and an Acrylamido Tertiary Butyl Sulfonate (ATBS)/acrylamide (AM) copolymer in mobilizing residual oil from carbonate. The surfactants are carboxybetaine based amphoteric surfactants SS-880 and SS-885. These candidates were selected based on an intensive evaluation process carried out in previous works at KFUPM, which includes fluid rheology, long-term thermal stability, interfacial tension (IFT), adsorption and microfluidic studies. Furthermore, contact angles were measured at high pressure and high temperature using a captive drop analyzer. Slug size and injection sequence optimization were also investigated through core-flooding experiments. Different injection scenarios including SW-SP-SW, SW-P-S-SW, SW-S-SW-P-SW and SW-P-SW-S-SW were also investigated to identify the best injection scenario. The coreflooding experiments were conducted at 90°C. The seawater (SW) used in this study is Arabian Gulf seawater having salinity of 57,000 ppm.

The results showed that surfactant-polymer combination and SW-SP-SW injection scenario were the best in terms of oil recovery. The optimum chemical combination was found to be carboxybetaine (0.05% wt.) and ATBS/AM (0.25% wt.). It was also observed that the recoveries were increasing proportionally to the slug-size. This indicates that the chemical injection sequence and slug-size have a significant impact on ultimate oil recovery. This is believed to be due to the advantageous synergies between the chemicals. The core-flooding experiments confirmed the importance of optimizing the design of CEOR processes taking into consideration the type of chemicals, concentrations, slug sizes, and flooding sequence of the different combination of seawater (SW), surfactant (5) and polymer (P).
Innovative Tailored Spacer System Helps Mitigate Losses and Enhance Cement Bond Log in a High-Lost Circulation Zone on the Largest UAE Offshore Field
Authors: Hamidzada Ahmedagha , Elhassan Azza , De Barros Adelson Jose , Alaleeli Ahmed Rashed , Torres Javier , Medina Ruben , Baouia Bilal , Agapiou Kyriacos
Published: March 2022

Lost circulation (LC) is commonly encountered in drilling and cementing operations and can be a costly problem that increases nonproductive time (NPT). Various methods can be applied to control losses—from applying best operational practices to incorporating LC control materials in treatment fluids and cement slurries. Among the cementing challenges, the loss of circulation can also be associated with poor zonal isolation and becomes more critical when zones between reservoirs should be covered to avoid sustained casing pressure (SCP) in the future and to extend the life of the well.

The application for this tailored spacer was the first one globally. Challenges addressed in the largest offshore field loss zone in the UAE included a high likelihood for losses during initial cementing, narrow equivalent circulating density (ECD) gradient, uncertainty in bringing cement to surface in the casing operation, and zonal isolation between reservoirs, formation, and caprock. As part of the best cementing practices, the design and tailoring of the spacers should be considered. Correct use allows the cement to cover zones of interest with less contamination, and cement properties can develop and interact efficiently with the formation.

Using a tailored spacer fluid system engineered to effectively and efficiently help prevent LC and maintain wellbore stability while preparing the wellbore to receive cement is discussed. The tailored spacer system uses additive synergies to help prevent LC in porous and fractured formations and enables control of rheological hierarchy and wellbore fluid displacement efficiency. The spacer was designed to optimize cementing operations where losses are observed and, in this case, incorporate additional LC materials to help prevent severe losses and achieve the desired top of cement (TOC). The tailored spacer system was pumped ahead of the cement slurry, to reduce permeability across the formation, with superior properties that help prevent fluid loss of the cement to the permeable formations.

Enhancing the cement bond and allowing an effective mud removal differentiate it from a conventional spacer. Using this spacer system enabled cementing goals to be achieved. Cement was brought to the surface, casedhole logs exhibited excellent cement bonding, and no SCP was registered, helping eliminate the need for unwanted remedial operations to secure the zonal isolation, which saves rig time.
Dynamic Data Integration in Dual-Porosity Dual-Permeability Reservoirs: Permeability Conditioning Perspective
Authors: Alramadhan Aymen , Lyngra Stig
Published: March 2022

Advancements in pore-scale and core-scale studies have provided an improved understanding of the micro- and macro-porosity nature of carbonate rocks and how the two systems interact. The interaction of the two systems in the presence of a third (fracture) and fourth component (vugs) has not been fully investigated in the industry. This paper demonstrates applicability and some limitations of permeability conditioning practices in dual-porosity dual-permeability (DPDP) systems. In addition, this work demonstrates how the permeability conditioning process can be used as a tool for dynamic classification and calibration of extreme permeability (super-k) intervals in dual-permeability systems.

A highly scalable parallel DPDP finite difference simulator is used to: Firstly, demonstrate the permeability conditioning process and how it impacts reservoir dynamics. Secondly, present cases where flowmeter (PLT) responses show a limitation in characterizing super-k intervals and its impact. Thirdly, demonstrate the role of enhancement factor in representing flood front movement for multiple super-k dominated reservoir realizations constrained by flowmeter and pressure transient permeability-thickness controls.

The results of this work expands on the representation of super-k intervals in dual-permeability systems in three main areas. Firstly, the decision to explicitly model super-k intervals as a fractured media or to implicitly model these features as a matrix permeability enhancement should be evaluated with use of enhancement factor combined with water breakthrough trends observed in the field. Secondly, the use of PLT responses to characterize super-k intervals should be made after careful evaluation of their responses before and after any well intervention. This step is crucial for proper permeability conditioning and in capturing reservoir dynamics of masked high flow intervals, i.e., new flow dominating features that appear only after the original super-k intervals have been plugged. Thirdly, as part of the integration of pressure transient results into a DPDP finite difference model, special consideration is needed for wells with a non-intersecting conductive fracture signature due to a limitation in the Peaceman formulation for DPDP reservoirs, which only considers cells intersecting the well for productivity index and PLT response calculations.

In summary, this paper provides guidance for geologists and reservoir engineers, through use of a permeability conditioning process, to dynamically classify and calibrate fractured/super-k intervals during the process of constructing full-field dual-porosity dual-permeability reservoir simulation models.
The Role of Dispersion in Enhanced Gas Recovery and Gas Field Pressure Maintenance
Authors: Van Dorp Johan J.
Published: March 2022

Objectives

Enhanced Gas Recovery (EGR) is the process whereby an inert gas like nitrogen or flue gas is injected in a gas reservoir to improve hydrocarbon gas recovery. One of the objectives of EGR is recovery of remaining gas in place at the prevailing abandonment pressure by sweeping native hydrocarbon gas with an inert gas.

This paper treats the reservoir engineering aspects of dispersion in gas displacement by nitrogen.

Methods

Relevant theory and knowledge from literature are applied to an example sandstone gas reservoir.

Results

The displacement is typically miscible, and the higher viscosity and density of the injected nitrogen over the native hydrocarbon gas improves the stability of the vertical displacement front. However, dispersion in the reservoir is another potential source of spreading of the front. This leads to early nitrogen breakthrough and a slowly growing nitrogen concentration in the production stream that needs to be dealt with prior to sales through N2 removal or dilution of the produced gas with other gas streams. Reservoirs with low formation dispersivity are therefore the most suitable targets for EGR. This leads to the selection of homogeneous reservoirs with short correlation distances of depositional features. Formation dispersivity is ideally measured upfront using a tracer push-pull test. As a result of the physics of the dispersion process a line drive with a large displacement well spacing provides an optimum selection as (horizontal or vertical) well configuration. Selection of high viscosity injection gas helps to increase the stability of the displacement front.

Novelty

Stabilization of the injection front by foam would significantly enlarge the targeted group of fields for EGR to include reservoirs with more adverse heterogeneity. R&D is required to establish a likely reduction in dispersion.

Accurate modelling of the mixing process is possible by tagging the injection fluid with a passive tracer while solving the advection equations explicitly using a higher order scheme to reduce numerical dispersion. Only physical dispersion at the sub-grid scale should be included. This modelling method could however lead to unstable displacement in the simulator because the density and viscosity contrasts are ignored.
Dual Heuristic Dynamic Programming in the Oil and Gas Industry for Trajectory Tracking Control
Authors: Al-Dabooni Seaar , Tawiq Alaa Azeez , Alshehab Hussen
Published: March 2022

This paper presents the state-of-the-art of the artificial intelligence algorithm, named dual heuristic dynamic programming (DHP) that uses to solve the petroleum optimization-control problems. Fast self-learning control based on DHP is illustrated for trajectory tracking levels on a quadruple tank system (QTS), which consists of four tanks and two electrical-pumps with two pressure control valves. Two artificial neural networks are constructed the DHP approach, which are the critic network (the provider of a critique/evaluated signals) and the actor-network or controller (the provider of control signals). DHP controller is learnt without human intervention via repeating the interaction between an equipment and environment/process. In other words, the equipment receives the system states of the process via sensors, and the algorithm maximizes the reward by selecting the correct optimal action (control signal) to feed the equipment. The simulation results are shown for applying DHP with QTS as a benchmark test problem by using MATLAB. QTS is taken in the paper because QTS is widely used in the most petroleum exploration/production fields as entire system or parts. The second reason for using QTS as a test problem is QTS has a difficult model to control, which has a limited zone of operating parameters to be stable. Multi-input-multi-output (MIMO) model of QTS is a similar model with most MIMO devises in the oil and gas field. The overall learning control system performance is tested and compared with a heuristic dynamic programming (HDP) and a well-known industrial controller, which is a proportional integral derivative (PID) by using MATLAB programming. The simulation results of DHP provide enhanced performance compared with the PID approach with 98.9002 % improvement. Furthermore, DHP is faster than HDP, whereas DHP needs 6 iterations, while HDP requires 652 iterations to stabilize the system at minimum error. Because of most equipment in the oil and gas industry has programmable logic control (PLC), the neural network block has already existed in the toolbox of the PLC program. Therefore, this project can apply in real by installing PLC to any equipment with DHP toolbox that connects to the sensors and actuators. At the first time, the DHP toolbox in PLC is learnt by itself to build a suitable robust controller. Then, the DHP controller is used during normal situations, while if any hard events happen to the equipment (the PID controller cannot handle it), the DHP toolbox starts learning from scratch again to overcome the new situations.
Non-Isothermal Compositional Simulation Study for Determining an Optimum EOR Strategy for a Middle-East Offshore Heavy-Oil Reservoir with Compositional Variations with Depth
Authors: Salimi Hamidreza , Sieders Bram , Rostami Javad
Published: March 2022

The objective of this study was to find an optimum EOR strategy for a Middle-East offshore heavy-oil reservoir that exhibits reservoir-fluids-properties variations with depth using non-isothermal compositional simulations that honor the fluids-compositional variations with depth. The observed compositional variations are such that the oil density changes from 20 °API in the crest to 11 °API in the deep part and the live-oil viscosity increases from 14 cP in the crest part to 449 cP in the deep part of the reservoir. Because the concept of thermodynamic equilibrium is not valid for the reservoir with compositional variations, we used the theory of irreversible thermodynamics to develop a compositional PVT model that captures the observed compositional and oil-properties variations with depth. Next, the PVT model was tuned against CO2 and hydrocarbon-gas swelling and MMP tests. Subsequently, we developed a compositional reservoir dynamic model that uses the single compositional PVT model and can simulate the degree of CO2/hydrocarbon-gas miscibility in oil. Then, we performed a dynamic IOR/EOR screening that includes water injection, hydrocarbon-gas injection, CO2 injection, water-alternating-CO2 injection, polymer injection, polymer-alternating-CO2 injection (PAG-CO2), and simultaneous polymer and CO2 injection (SPCO2). For simultaneous polymer and CO2 injection, polymer was injected at the top while CO2 was injected at the bottom. The simulation runs of these scenarios were elucidated in detail.

The developed compositional PVT model successfully reproduces the observed fluids-properties and compositional variations with depth. In this way, the calculated fluids properties are continuous with depth because there is only a single PVT model for a single PVT region. The performances of different EOR scenarios were compared with each other. The simulated incremental oil recovery increases in the sequence of water injection, hydrocarbon-gas injection, WAG-CO2 injection, CO2 injection, polymer (22 cP) injection, PAG-CO2, and SPCO2. The reason for higher incremental recoveries with combined CO2-polymer scenarios is that both the macroscopic sweep (with polymer) and microscopic displacement efficiency (with CO2 and polymer) remain high. Although the CO2 injection pressure is lower than the MMP, the condensing- and vaporizing-gas drives are very efficient to the remaining oil saturation to low values (< 0.10). The other advantage of SPCO2 injection is that the intermediate and deep layers are well contacted and swept by the injected fluids. At the crest scale, combined CO2-polymer scenarios can increase the do-nothing recovery by 85–119%.