bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract

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.