bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimized Alkalinity for EOR Purposes in Sandstone Reservoirs
Authors: Mamonov Aleksandr , Khan Md Ashraful , Puntervold Tina , Strand Skule 
Published: October 2018

Abstract
With increased environmental focus and sustainability, classical water-based EOR with surfactants or polymers meet larger implementation scepticism. This has increased the attention toward water-based EOR methods with low environmental impact and lower costs, such as Smart Water and alkaline flooding. Both methods are based on the establishment of alkaline conditions in the formation. Chemical interactions among the rock minerals, reservoir fluids, and injection brine can be reflected in the pH of the produced water. Thus, the scope of this work is to investigate the development and transportation of pH through porous media during 1) low salinity (LS) Smart Water flooding, and 2) alkaline LS (alk. LS) waterflooding.
Outcrop sandstone cores were used in core flooding experiments. Several pH-screening tests were performed to study the pH development during waterflooding. The ability of LS and alk. LS injection brines to increase the pH in sandstone core material with different mineralogy was compared, and the effect of pH on oil recovery was confirmed in an oil recovery test.
The results of the pH-screening tests by LS brine injection showed a potential for increasing the effluent LS water pH up to 2 units in comparison to its initial pH-value. The oil recovery test performed on the same core material showed almost 10% incremental oil recovery during LS flooding in secondary mode, in comparison with formation water (FW) flooding. pH-screening tests with alkaline LS brine injection showed low potential for extra alkalinity above that obtained by LS brine injection. Transportation of alkalinity through a mineral system with large surface area seemed to be challenging due to pH buffering from brine/mineral interactions as well as from chemical interactions involving inorganic cations from the formation water.
Based on the experimental results, ion exchanges between rock minerals and injected water can influence the reservoir pH and induce the wettability alteration. These chemical interactions can result in both development and consumption of alkalinity depending on the type of injected brine and chemical reactivity of the minerals. It was concluded that an in-situ generation of alkaline conditions at the waterfront seemed to have larger potential for EOR purposes than transferring the alkalinity of the injected brine through the reservoir.
Hydraulic Fracturing Treatment of Low-Permeability Coal Seam Gas Reservoirs with Finely Layered Coals
Authors: Zhang Xi , Wu Bisheng , Connell Luke , Han Yanhui , Jeffrey Robert 
Published: October 2018

Abstract
In this paper, a fracture mechanics model that deals with fracture growth in layered low-permeability rocks is presented and applied to hydraulic fracturing stimulation of coal seam gas reservoirs. The model uses the conventional pseudo-3D treatment by which the vertically planar fracture is divided into cells along the horizontal direction. For each cell, the fracture deformation is represented by a 2D plane-strain fracture. To ensure numerical stability, the model uses an optimization method based on the fluid volume increase of each cell and the solutions for each cell can be obtained in parallel when using a computer with multiple CPU cores. The method was verified based on the comparisons with existing solutions and the computational speed can be significantly increased by using parallel computing. Numerical examples are presented to illustrate cases that result in fracture geometrical complexities caused by material properties contrasts between the thin softer coal seams and the adjacent stiffer rocks. The local horizontal stresses in each layer are calculated based on the layer-independent uniform horizontal strain assumption. The overburden stress is given. The fracture length and opening in the coal can be larger than other layers if the coal is subject to a smaller stress. This will promote growth of the fracture plane to include coal seams that do not receive injected fluid at the wellbore. The well developed fracture opening in the coal can be impeded by an increase in the confining stress of the coal. The fracturing produces wide propped channels below the coal seam in the low stress rock that exists there. These conductive channels allow flow of gas and water to the wellbore. The stress uncertainty is considered and interestingly the injection pressure trends are insensitive to the variation of local stresses. There is a process that favors growth in the softer coal seams for all cases, which yields a slight and progressive increase in the injection pressure.
Planning and Drilling Execution of Early Permian Wells in Two String Design by Implementing New Drilling and Cementing Technologies
Authors: Shaban Alex , Zaman Mohammad , Dedigama Thivanka , Saunders Troy 
Published: October 2018

Abstract
The development of Early Permian reservoirs in the Fairview Field is limited by highly depleted shallower Bandanna coal seams and naturally fractured formations that would not allow to reach the original geological goals. Offset wells in the area had been executed as three string well design due to long open hole section across depleted Bandanna and multiple loss zones. Multi-stage cementing was required to ensure there is proper zonal isolation. These resulted in significant incremental cost to achieve 5-1/2″ production casing. Through the depletion of upper coals, fracture pressure in these zones has decreased due to reduction in pore pressure.
Drilling in two string design carries higher execution risk due to long open hole section, depleted formations and differential sticking, highly fractured formations, narrow window between fracture gradient and pore pressure, and multiple loss zones which demands special techniques for treatment of loss zones and hole stabilisation while drilling. Considering the downhole conditions, which pore pressure ranging from 2 to 9 ppg in the different formations, the importance of zonal isolation, establishing barriers in aquifers and achieving overall cement coverage is also extremely important.
With introduction of various new LCM products, cement plugs, foam cementing, RCD for drilling with no returns (blind drilling), Santos has achieved major success developing Early Permian fields. This Paper describes how two string design was successfully implemented to drill Early Permian wells. This paper serves as an operational guide to ensure challenging depleted and highly fractured zones can be successfully drilled while minimising risks.
Quantifying Gas Content in Coals Using Borehole Magnetic Resonance
Authors: Hopper Timothy , Neville Thomas , O'Neill Keelan 
Published: October 2018

Abstract
Traditional approaches to saturation evaluation in conventional oil and gas reservoirs rely on relationships between resistivity and water saturation. These relationships are challenging to apply in coals due to complexities in their pore systems and gas trapping mechanisms. Therefore, geophysical log-based methods are not commonly employed for saturation evaluation, and core canister desorption measurements are the standard approach for gas content evaluation. Desorption measurements present their own challenge due to the unknown and variable volume of gas lost during core recovery, so an in-situ measurement of gas content is desirable.
Advanced magnetic resonance measurements provide a resistivity-independent saturation evaluation that have been employed in the oil and gas industry for the past approximately fifteen years. However, previous approaches to these types of measurements have focused on the evaluation of conventional reservoirs and hence free gas, oil, and water volumes, and have lacked sensitivity to quantify adsorbed gas, which has a unique magnetic resonance response. A novel magnetic resonance acquisition scheme has been developed that provides sensitivity to both adsorbed and free gas, as well as water, allowing for the complete evaluation of fluid content in coal seams. This measurement has been employed in evaluating coal gas content for coal seam gas evaluation and coal mining optimisation with encouraging results.
Mechanistic Modeling of Low Salinity Water Injection under Fracturing Condition in Carbonate Reservoirs: Coupled Geochemical and Geomechanical Simulation Study
Authors: Hosseini Seyed Moein , Kord Shahin , Hashemi Abdolnabi , Dashti Hossein 
Published: October 2018

Abstract
The main problem during field scale implantation of low salinity water injection (LSWI) is the decline in injectivity versus time. Moreover, the actual mechanisms that result in incremental oil recovery are not completely known. In previous studies, the geomechanical effects have not been considered, and pore volume changed while bulk volume is still constant which in turn can bring uncertainty to the simulation results. In this paper, both geochemical and geomechanical models have been coupled with the flow model. For coupling geomechanical model, three equations have been solved simultaneously in each time step. Then, the geochemical model has been coupled by adding the necessary aqueous and mineral reactions and ion concentration of both formation and injection waters. Increasing the Ca2+ concentration in the injected brine cause a reduction in the ultimate oil recovery. Also, increasing SO42− concentration in the injected brine up to about 70 ppm, resulted in increased oil recovery, while increasing the concentration caused a reduction in oil recovery. Injection above formation parting pressure (FPP) is beneficial but, there is a high uncertainty during injection above the FPP that can affect ultimate oil recovery and net present value. The results of this study show that geomechanical and rock parameters have intensive effects on the simulation results and rough estimating them in the simulation process can result in major errors and uncertainties. Further, it is very important to precisely include the dominant mechanisms of low salinity or smart water process during simulation studies.
Successful Field Application of Pillar Fracturing Technique in Water Injection Well for Creation of Highly Conductive Conduits
Authors: Bhagavatula Ramkamal , Rajagopalan Vijay Shankar , Chellappan Suresh , Al-Ashwak Amna , ElMofti Mohamed , Boueshi Alaeldin , Eid Waleed , Allam Ahmed , Abdelbaky Amr , Davis John 
Published: October 2018

Abstract
This paper discusses the successful application of a pillar fracturing technique in a water injection well wherein a major operator previously experienced poor injectivity within the target zone.
The aim of the pillar fracturing technique was to achieve the highest possible fracture conductivity to enhance water injectivity for reservoir pressure maintenance. This technique creates infinite conductivity channels with proppant distributed within the fracture as aggregates or groups separated by clean fluid. These proppant groups function as pillars to hold the fracture open and help enable fluid flow in the open channels between proppant pillars. The conductivity of a partially open fracture with proppant pillars can be several orders of magnitude greater than that of a conventional fracture filled with proppant after closure. After a pillar style hydraulic treatment, the propping agent remains in the fracture grouped to form pillars because of the sticky resin that was applied to the proppant just before being blended (intermittently) into the fluid system that was pumped during the treatment. This helps the grains in the resulting pillars to adhere together and help prevent the fracture from entirely closing, forming open conduits for fluid flow. The overall success of this fracturing stimulation treatment depends on the sequenced pumping technique, allowing the propping agent to form proppant aggregates during their placement into the formation.
This paper presents the enhanced pillar fracturing technique, pre-job well analysis and design, Minifrac data calibration, and actual pumping operation execution. The well intersects a reservoir with sandstone lithology that had not been fractured previously. The sandstone formation is subdivided into three intervals of 60, 40, and 60-ft thickness, with distinct shale layers separating them. Based on the log interpretations and formation geomechanical analysis, two pillar fracturing stages were determined necessary to treat the entire targeted formation and maintain balanced injectivity in all three intervals. An optimum hydraulic fracturing design was developed and executed to deliver optimal well performance. Actual operational execution involved use of specially designed surface equipment and adhesive enhancement proppant coating to install highly conductive flow paths while maintaining reservoir and proppant pack stability. This resulted in a successful treatment that sustained 16,000 barrels of water injection per day (BWIPD).
The successful application of the pillar fracturing technique in this well motivated the operator to extend the pillar fracturing technique to other injector and producer wells.
Inflatable Packer Anchor System Enables Rigless Installation of an Insertable Progressing Cavity Pump in South Oman
Authors: Osorio Alejandro , Ford Francis , Montilla Benigno Segundo 
Published: October 2018

Abstract
Current market conditions in the oil industry call for cost effective well intervention methods to optimize production in wells completed with Insertable Progressing Cavity Pumps (I-PCPs). Rigless rod-string conveyance of I-PCP's traditionally rely on Pump Seating Nipples (PSNs) or mechanical-set I-PCP anchoring devices in wells without PSN's. Although the installation of an I-PCP on a PSN is a reliable method, it requires a PSN to be originally installed within the production tubing, which limits the I-PCP setting depth to the location of the PSN. Rod-string conveyance of mechanical-set I- PCP anchoring devices is limited by the rod string's effectiveness to transmit the required axial loads to setting depth, which becomes increasingly challenging in extended-reach conditions. Other challenges with I-PCP installations include location of previously installed PSN's and positive anchoring to facilitate disengagement of the rotor without unseating the I-PCP for flush-by operations.
An inflatable packer anchoring device has been developed to simplify rigless installation of an I-PCP without the need of a seating nipple. The device relies only on hydraulic pressure while eliminating the need for axial loads during its setting sequence. The rod string deployed inflatable packer I-PCP anchoring device incorporates inflatable packer technology in conjunction with a hydraulically-actuated slip mechanism. It is equipped with seal cups and a shearable intake sub to obtain the required pressure competence to confirm tubing integrity and enable its setting sequence while maximizing flow-through capability after it is set. The system can be retrieved by applying overpull to shear its release pins allowing the inflatable packers to deflate and the mechanical slips to retract.
The first installation of this system proved its optimal functionality by successfully setting an I-PCP in 3-1/2" production tubing in a vertical well in Oman's Sadad field. The I-PCP was deployed on rod string in conjunction with the inflatable packer anchoring device to setting depth. The system was set by applying pressure with a flush-by unit pump via the tubing-rod annulus, and the well was immediately placed into production.
The objective of this paper is to provide a technical explanation of this innovative and unique technology, share the lessons learned from its first installation, and discuss its potential to improve the current capabilities of I-PCP technology while reducing operational cost and optimizing PCP/I-PCP completion design.
A Rigorous Yet Simple Technique for Coupled Reservoir and Geomechanics Simulation
Authors: Matsunaga Ryotaro , Watase Seishiro , Furui Kenji 
Published: October 2018

Abstract
Many applications in the petroleum industry require both an understanding of the porous flow of reservoir fluids and an understanding of reservoir stresses and displacements. Historically reservoir simulation has accounted for geomechanical effects by simple use of a rock compressibility. This assumption results in pore volume to change only with pore pressure. On the other hand, according to the poroelasticity theory, pore volume should change not only with pore pressure but also with confining stresses or volumetric strains induced by rock deformation. This difference in the governing equations poses a great challenge when coupling reservoir flow and geomechanics models.
In this study, we develop a mathematical expression that relates the pore volume compressibility used in the porous flow equation to poroelasticity parameters defined in the geomechanics model. Secondly, in order to implement consistent pore volume changes between the reservoir flow and geomechanics models, we derive a pore volume correction term for the porous flow equation, which accounts for volumetric strain changes and rock matrix deformation. As demonstrated in the paper, the correction term can be easily implemented in sink/source terms (or "fictitious well" term), which are readily available for most commercial reservoir flow models. With this simple implementation, virtually any existing commercial reservoir simulation models can account for geomechanical effects via modular coupling techniques.
In this work, we compare three different techniques for coupling reservoir flow and geomechanics. One technique uses an explicit algorithm to couple reservoir flow and displacements in which flow calculations are performed every time step followed by displacement calculations (i.e., One-way coupling method). A second technique uses an iteratively coupled algorithm in which flow calculations and displacement calculations are performed sequentially for the nonlinear iterations during each time step (i.e., Iterative partitioned coupling method). The third technique uses a fully coupled approach in which the program's linear solver must solve simultaneously for fluid-flow variables and displacement variables (i.e., Monolithic coupling method). Using Mandel's problem, example simulations are presented to highlight accuracy and computational efficiencies in these coupling techniques.
To the best of the author's knowledge, this is the first paper to present a coupling technique to consider rigorous geomechanical effects in the porous flow equations. The coupling method proposed in this study can be applicable for virtually any existing reservoir and geomechanics simulation models. The proposed coupling techniques are easily extended to multiphase flow and poroelastoplastic problems. All problems in this paper are described in detail, so the results presented here may be used for comparison with other geomechanical / porous-flow simulators.
Optimisation of Engineered Water Injection Technique in Carbonate Reservoirs: A Case Study
Authors: Adegbite Jamiu Oyekan , Al-Shalabi Emad Walid 
Published: October 2018

Abstract
Engineered/low-salinity water injection technology is one of the latest promising techniques for improving recovery in both sandstone and carbonate reservoirs. In this paper, the optimization of engineered water injection technology is investigated using three 5-spot reservoir models including heterogeneous with channeling, heterogeneous with gravity underride, and homogeneous. The net present value was chosen as an objective function for the study. 18 design parameters were selected for the study including reservoir, operational, and economic parameters. The machine learning and artificial intelligence tools were utilized. Response Surface Methodology and Designed Exploration and Controlled Evolution algorithms were implemented for sensitivity analysis and optimization studies, respectively.
The sensitivity study showed that oil price, tax rate, and initial oil saturation are among the most significant design parameters on the net present value for the three models investigated. Moreover, the findings showed that developing the gravity underride model requires more attention as being the most sensitive model with 13 influential design parameters. The optimization study highlighted the need for engineered water injection in the secondary mode to achieve the best profitability out of the three models. Also, it is recommended for an operator to invest in the homogeneous, followed by the channeling, and least the gravity underride models due to the corresponding net present values of $1.44 million, $1.39 million, and $0.96 million, respectively.
The study highlighted the importance of selecting the most suitable objective function for achieving the project profitability by comparing net present values vs. oil recovery as objective functions. In addition, this study can be used as a guide for using artificial intelligence tools to understand the most influential engineered water injection design parameters that affect profitability, and hence field scale developments can be conducted with more certainty and lower risk.
Maximizing Oil Recovery through Gas-Cap Perforation in Strong Water-Drive Reservoir
Authors: Abdulhadi Muhammad , Mansor Mohd Najmi , Amiruddin Nurul Azrin , Tran Toan Van , Jacobs Steve , Abd Wahid Muhammad Izad , Usop Mohammad Zulfiqar , Zamzuri Mohd Dzulfahmi , Dolah Khairul Arifin , Munandai Hasim , Yusop Zainuddin 
Published: October 2018

Abstract
Reservoir X-7, a watered-out reservoir in Field B, was successfully revived by perforating the original gas-cap zone to maximize oil recovery, which increased the recovery factor (RF) from 40% to 46%, resulting in approximately 2,300 BOPD through multiple perforations.
Maintaining the oil column sandwiched between gas and water is the standard practice to maximize oil recovery in a strong water-drive reservoir. Despite having a strong aquifer and a thick gas cap, Reservoir X-7 has produced continuously for 30 years without any gas reinjection. The reservoir was producing at 99% watercut, indicating the original oil column was already swept. Subsequent material balance study and saturation log results confirm that oil migrated into the original gas cap. Given the reservoir condition, an unconventional approach was proposed to produce the oil column through the original gas-cap zone.
The first gas-cap perforation for Well B-07 successfully produced 500 BOPD, so it was decided to perform three additional perforations (additional perforations) for Wells A-01, B-12, and B-16, which were successful with a total 2,000 BOPD oil gain from the three wells. Subsequent additional perforations was performed in Well B-07 after the original additional perforations watered out. However, the new additional perforations and subsequent ones in Well B-11 resulted in gas rather than oil. Both wells were shut in. Once the new perforations are watered out, the remaining oil potential in Reservoir X-7 will be confirmed by reopening well B-07 and B-11 until either oil or water is produced. The approach has so far provided approximately 2,300 BOPD of incremental oil production, extending well life by more than 24 months and allowing the RF to increase from 40% to 46%. It delivered encouraging results and opened up opportunities for other reservoirs.
This paper provides valuable insight into the case study and lessons learned in terms of maximizing oil recovery using original gas-cap perforation. This approach is highly recommended as the production enhancement method for maximizing oil recovery, particularly in mature fields with similar reservoir conditions.