bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Assessment of the Application of Propellant Enhancement to Conventional Wells
Authors: Campin David 
Published: November 2020

Abstract
Propellant enhancement is a method of increasing permeability through the application of a transient high pressure event to the target formation. As distinct from hydraulic fracturing, propellant enhancement does not involve the application of chemicals or water and consequently does not present the potential for legacy environmental issues. This paper compares the regulatory aspects of propellant enhancement within the states of Australia and also the differences between environmental impacts.
A series of propellant enhancements were undertaken for a suite of gas wells in the Surat Basin, Queensland. Propellant charges in the range 18-30 kg were initiated, with deflagration times in the range 500-1,000 milliseconds. The compliance regime for the transport, storage and use of propellant is established under the state’s Explosives Act 1999 as well as the Petroleum and Gas (Production and Safety) Act 2004 and the Environmental Protection Act 1994.
There are three categories of fracturing used to increase permeability: explosive fracturing; hydraulic fracturing; and propellant enhancement. Explosive fracturing applies a very high pressure transient over a period of a few microseconds and can cause local, radial fracturing but with less desired compaction; hydraulic fracturing applies a lower pressure but over a longer period and with greater surface power, resulting in fractures that can extend 200-300 m, largely in the vertical plane; and propellant enhancement, which applies a mid-range pressure over a period of 10-1,000 milliseconds, resulting in fractures extending tens of metres but with random distribution. Residuals from the deflagration process are nitrogen, hydrogen chloride, water and carbon dioxide. There are no precursors for the BTEX suite and no conditions arising that could produce BTEX.
A prime question was to determine whether propellant enhancement is captured under the term ‘hydraulic fracturing’ in states’ regulations across Australia. Propellant enhancement is a technology with very few environmental impacts. Vehicular movements to support propellant enhancement are less than five percent of those to undertake hydraulic fracturing on the same formation. There is no requirement for waste water treatment.
Influence of Adsorption Layer Thickness and Pore Geometry in Tight Compressible Shales Subject to Gas Production
Authors: Abolghasemi Erfan , Østebø Andersen Pål 
Published: November 2020

Abstract
In tight shales, gas is stored in both free and adsorbed forms where the latter can make a significant or majority part of the gas in place. When the adsorbed layer thickness becomes of similar magnitude as the pore radius the adsorption can also affect the flow performance. We consider a 1D model for shale gas production where we implement adsorption with the adsorbed layer thickness as function of pressure, pore geometry where the pores are n-spherical (for 1 &lt; n &lt; 3). A higher n indicates more spherical pores, while a lower n means more fracture shaped pores. The shale is assumed to be compressible and its porosity and pore radius reduce with pressure depletion. The effective pore radius, which also depends on adsorption layer thickness, controls both intrinsic and apparent permeability. This study will address gas production by natural pressure depletion and the impact of the adsorption layer in the flow-compaction interplay. Marcellus shale data are used as input.
For a given compressibility and hence porosity-pressure relation, the pore radius is less reduced at a high n than for a low n. The adsorbed layer thickness is assumed to be pressure dependent only, and fills a greater volume in the pores when the pores are more spherical (high n). Increasing the maximum adsorption layer thickness makes the adsorbed layer fill more of the pore volume and gas in place. The increased volume fraction of adsorbed gas reduces the free gas saturation and the apparent permeability of the gas, resulting in delayed production compared to systems where the pores are less spherical (lower n) and the adsorbed layer is thinner. Desorption is not very significant until pressure is reduced well below the initial value and mainly free gas is produced at early times. Hence, systems with more adsorbed volume fraction see lower recovery at a given pressure. Pressure depletion causes both the pore radius and the adsorbed layer to be reduced. The change in adsorbed layer with pressure is lower at high pressure and greater at low pressure, while pore radius changes more linearly with pressure. The free gas saturation can increase with pressure depletion (time) for low compressibility cases, or can reach a minimum before increasing in high compressible cases. It was observed that compressibility and production from the adsorbed layer both contributed significantly to recovery. Setting either the porosity or the adsorbed layer thickness constant (same as for the initial pressure condition) resulted in lower recoveries. Setting both constant gave the lowest recovery.
PACT – Digital, Fail-Safe, Wellhead Annulus- And Production Tree Valves Actuator Control System
Authors: Johansen Espen Sten , Fredheim Dag Ketil , Huuse Tom , Volkers Richard , Hansen Dag Almar , Petersen Christian 
Published: November 2020

Abstract
In the drive for remote operations, reducing operator costs and reducing emissions and CO2, digitalization of sensors and control systems is imperative. To date, valves on wellheads and trees have predominantly been controlled by hydraulic actuators that are not ideally suited for fully remote operations.
A new, innovative, electric actuator has been developed under a Joint Industry Project (JIP) by Equinor, Baker Hughes and TECHNI. This actuator is designed for fail-safe, critical operations offshore and is subject to stringent safety design requirements. The key motivation is reducing CAPEX and OPEX for offshore installations, while increasing availability of wells while providing improved monitoring and condition based, predictive maintenance.
The electric actuator that was developed in the program has a patent pending fail-safe mechanism with extremely fast closing time (less than 1 second) to ensure well containment during critical situations. The actuator is designed to be a drop-in replacement for NoBolt™ CHA actuator solutions and is suitable for most standard wellhead and tree designs, sizes and pressure ratings. In the new all-electric design, a multitude of sensors in combination with an OPC-UA architecture, enables data-driven insights from the systems in operation.
The program was started in 2017 and has resulted in a system at Technology Readiness Level (TRL) 4 (on 0 to 7 scale) with TRL 5 testing planned in 2020 yielding it ready for field installation.
Effect of Pyrite Oxidation on Flowback Water Properties During Hydraulic Fracturing in Calcite-Rich Shales
Authors: Zeng Lingping , Iqbal Muhammad Atif , Reid Nathan , Lagat Christopher , Hossain Md Mofazzal , Saeedi Ali , Xie Quan 
Published: November 2020

Abstract
Megalitres of water with associated dissolved oxygen are injected into shale reservoirs during the hydraulic fracturing process. Pyrite oxidation, if it occurs in-situ, can generate extra H+, thereby dissolving calcite and increasing the salinity of flowback water. The process of calcite dissolution may soften the hydraulic fracture surfaces, resulting in proppants embedment and thus decreasing fracture conductivity for calcite-rich shales. Therefore, it is of vital importance to understand the impact of in-situ pyrite oxidation on fluid-shale interactions, particularly calcite dissolution, to help industry screen and design hydraulic fracturing fluids in shales. Spontaneous imbibition experiments were performed using Marcellus shale samples under three conditions: i) ambient conditions, where the fluid was in equilibrium with atmospheric air throughout the tests, ii) limited O2 condition, where the fluid was free equilibrated with air in a sealed cylinder and iii) vacuum condition, where the fluid in a sealed cylinder was degassed. The pH and ion concentrations were measured upon completion of the experiments. To further explore how pyrite oxidation affects fluid-rock interactions, we performed geochemical simulations with considerations of mineral dissolution (calcite, albite, quartz, chalcopyrite, pyrite and dolomite), surface complexation and the dissolved O2 on fluid salinity.
The spontaneous imbibition tests show that the salinity of fluids in ambient conditions is higher than the limited or vacuumed saturation fluids, confirming that pyrite oxidation generates H+ which would dissolve minerals such as calcite and dolomite. This result is also supported by the observed pH and the concentration of dissolved Ca2+. The fluid fully saturated with O2 has the lowest pH and highest Ca2+ compared to limited O2 saturation condition and degassed condition. Scanning electron microscopy analyses show that brine saturation barely affects the morphology and elemental distribution of pyrite at ambient conditions, suggesting that pyrite oxidation plays a minor role in fluid salinity. Geochemical modelling also indicates that although pyrite oxidation can slightly increase fluid salinity, the salinity increment is less than 5% of reported flowback water salinity, confirming that the dissolved O2 in hydraulic fracturing fluids has a minor effect on fluid-rock interaction thus the salinity increment. This work demonstrates that pyrite dissolution at lab-scale would overestimate the impact of fluid-shale interactions and calcite dissolution in reservoir conditions. We prove that pyrite dissolution in in-situ conditions results in minor implications for fluid-shale interactions and calcite dissolution. Consequently, we limit intrinsic uncertainty of hydraulic fluid design associated with pyrite oxidization especially for calcite-rich shales.
Unlocking the Hidden Oil: How LRLC Reservoirs Contributed to 800 bopd of Production in a 30 Year-Old Offshore Brownfield
Authors: Tham Su Li , Chiew Kwang Chian , Hassani Hamed , Chang Claire Li , Huong Chii Seen , Ariffin M Hafizi 
Published: November 2020

Abstract
Production Enhancement (PE) opportunities in a 30 years-old Field D in Balingian province, offshore of Sarawak, Malaysia are dwindling. Behind casing opportunities (BCO) in relation to bypassed pay with good reservoir properties are either already perforated and produced or too costly and complex to be executed due to well issues. An in-house evaluation tool, Resolution Enhanced Modelling (REM), was developed by PETRONAS Petrophysics Department to evaluate and characterize thin beds or laminations. These Low-Resistivity-Low-Contrast (LRLC) sands are commonly bypassed as conventional logging tools cannot resolve their true parametric values and the apparent log responses across these zones appeared as shaly sand. By running REM across these intervals, the properties of the thin sands can be properly characterized, improving the net pay and economics of perforating and producing these reservoirs. In addition, a Rock Type (RT) based technique was used to evaluate some LRLC candidates in Field D.
REM was run on LRLC sections in idle wells to evaluate their potential. To derisk and test the methodology, Well A3 with relatively more promising results was chosen as the first well to be perforated. Moreover, both strings of Well A3 were idle which makes it operationally easier to carry out the perforation job. From the initial analysis, the LRLC intervals in Well A3 could contribute to additional reserves of 0.3 MMstb with start rate of 300 bopd.
The job required usage of barge assisted coiled tubing to pump cement and shut off existing high watercut zone and slickline to perforate through tubing. The actual job duration was prolonged from 30 days to 50 days due to monsoon season, driving the cost up to twice the planned amount. Post perforation, the initial oil rate was tested to be 500 bopd. After increasing the choke size, the well could flow at 800 bopd. Convinced by the success of Well A3, the same methodology was applied to Well C8 located at the north side of the field. Well C8 encountered operational difficulties such as lower than expected top of cement and perforation gun malfunction, resulting in only 54% of the proposed depth being perforated. Well C8 produced high gas, with initial well test rate of 10 bopd.
Managing a brownfield where the easy oil is mostly exhausted can be challenging. Therefore, the team has to be more creative in unlocking the remaining oil and prolonging the life of a well. By using REM, the overlooked potentials hidden in LRLC sands can be accurately estimated, making the economics to perforate them more attractive to pursue.
Impact of Injection Temperature on CO2 Storage in the Surat Basin, Eastern Australia
Authors: Ribeiro Ayrton , Sedaghat Mohammad , Honari Vahab , Hurter Suzanne 
Published: November 2020

Abstract
In CO2 storage projects, CO2 usually enters the target reservoir at a lower temperature than that of the surrounding rock and its density is increased. The injection temperature affects how much CO2 can be stored. In this work we investigate the impact of heat exchange during CO2 injection into the Surat Basin, Australia, using integrated reservoir modelling. We evaluate the aquifer storage and sealing capacities, as well as pressure build up and CO2 plume migration.
Flow simulations of CO2 injection into the Precipice Sandstone were conducted with injection temperature from 40 to 80°C. The modelling domain consists of the reservoir sandstone, an overlying transition zone (muddy sandstone) and above it, the ultimate seal. The distribution of porosity, permeability and capillary pressure is heterogeneous. Heat exchange between rock and fluids was enabled in the commercial simulator to evaluate changes in fluid properties due to wellbore cooling. The initial temperature was set to 80°C. The injector’s wellbore pressure drop is modelled honouring a constant well head pressure of 15,000 kPa. The maximum allowed bottom-hole pressure is 90% of a thermally reduced fracturing pressure.
The viscosity of water and CO2 increases during cooling of the near wellbore zone; thus, pressure build up grows faster in the case of lower injection temperatures. Although the bottom-hole pressure becomes higher, injection rate is constrained by well head pressure. Heat exchange also increases the density and saturation of CO2 at the plume edge, which causes a sharper and faster advancing front. Higher pressure in the reservoir forces fluids to migrate to the transition zone, which also reduces its temperature. CO2 flows preferentially through the lowest capillary pressure channels and is able to permeate slightly into the transition zone. These physical conditions at the bottom of the well (lower temperature and higher pressure) lead to a denser CO2 plume and a greater mass is stored in the reservoir each year.
This work analyses non-isothermal injection of CO2 into an aquifer using integrated reservoir modelling. It illustrates how reservoir cooling may increase the rate of CO2 storage and slight migration to the transition zone.
Modelling the Impacts of Water Blocking During Gas Production from Compressible Shales
Authors: Andersen Pål Østebø , Volkov Vladislav 
Published: November 2020

Abstract
The aim of this work is to study shale gas production subject to water blocking in compressible shale. Water blocking is a capillary pressure end-effect causing the wetting phase (e.g. water) to accumulate near the transition from a porous medium to an open medium; in this context, a transition from shale matrix to a hydraulic fracture. Shale is considered a tight porous medium with ultralow permeability, and hydraulic fracturing is essential to obtain economical production. Water is frequently used as a fracturing fluid, but its accumulation at the matrix end-face reduces the gas mobility and can lead to rapid decline of gas production rate.
The tight nature of the shale as a porous medium also introduces non-standard flow and storage mechanisms. This work develops a mathematical model that accounts for apparent permeability, compressibility of gas and shale, gas adsorption, Forchheimer gas flow, and multiphase flow parameters like relative permeability and capillary pressure, which depend on wettability. The behavior of the model at steady state production is explored to understand the impact of the various mechanisms.
Best Practices for Operations in HFTO Prone Applications
Authors: Hohl Andreas , Kulke Vincent , Kueck Armin , Heinisch Dennis , Herbig Christian , Ostermeyer Georg-Peter , Reckmann Hanno 
Published: November 2020

Abstract
Vibrations impact the drilling process by reducing reliability, increasing maintenance costs and reducing rate of penetration and drilling efficiency. Herein, torsional vibrations are typically distinguished into low-frequency torsional oscillations and stick/slip with frequencies below 1 Hz and high-frequency torsional oscillations (HFTO) with frequencies up to 450 Hz. HFTO is associated to high accelerations with critical values above 150 g and dynamic torsional torque values above the make-up torque. A HFTO mitigation strategy is mandatory for prone applications to guarantee high reliability and drilling efficiency.
In this work different best practices for mitigation of HFTO and their interdependency are discussed along with their operational efficiency. The discussed scenarios include coupling between stick/slip and HFTO, different formation properties, and tools that are used for vibration mitigation such as isolators and mud motors. The analysis includes the review of time-based acceleration and load data with a sampling frequency of 1000 Hz and 2500 Hz and numerical modeling to determine the application and environment specific critical range of operational parameters in a holistic approach. The extracted critical range of operational parameters enables operations to optimally adjust parameters with a minimum of torsional loads and optimal drilling efficiency.
This analysis again unveils that the general effect of HFTO is triggered by the cutting forces between PDC bits and hard and dense formation. It is shown qualitatively and quantitatively that high WOB values and low rotary speed values correspond to HFTO. The case study shows opportunities of a reduction of HFTO related loads by increase of the rotary speed without compromising the ROP in specific applications and environments. It is shown that special tools for vibration mitigation influence the stable operational window and need to be considered.
Depending on the scenario a complete mitigation of HFTO or at least a significant reduction of loads can be achieved by targeted adjustment of operational parameters and use of tools for vibration mitigation. The drilling process can be optimized leading to a reduced cost of the well delivery since HFTO can be a major cause for non-productive time if not handled properly.
A Fully Coupled 3D Finite Element Simulator for Staged Hydraulic Fracturing in Horizontal Wells
Authors: Meng Siwei , Bao Jinqing , Yang Chenxu , Cheng Wei , Zhang Guangming 
Published: November 2020

Abstract
Staged hydraulic fracturing in horizontal wells is one of the most popular techniques in developing conventional and unconventional reservoirs, where multiple fractures initiate and propagate simultaneously and then interact with each other. It is shown in hydraulic fracturing practices that these interactions lead to unsatisfactory production performance in many fractures. It is of great importance to develop a reliable hydraulic fracturing simulator that can completely effectively take these interactions into account and predict fracture behavior accurately.
We develop a fully coupled 3D hydraulic fracturing simulator with the finite element method, where the interaction between fractures is completely taken into account. We develop a finite element equation to describe fracturing deformation and propagation based on linear elastic fracture mechanics, another one to describe fluid flow and leak-off within fractures, and friction equations to describe the effects of the perforations and tortuosity. We solve these three equations in a fully coupled and implicit way, and obtain fluid pressure, fracture width, and injection allocations between fractures in every step simultaneously.
Followed by the method’s verification with experiments, we simulated staged hydraulic fracturing with the coupled finite element simulator and investigated the interactions’ effects. It was found in the simulation that the perforations have the ability to make the injection allocated very even. However, fractures propagate and evolve in very different manners due to the interaction between fractures. Some fractures are far longer than others, while their fracture widths close to the wellbore are far smaller. Due to the stress shadows arising from the fracture interactions, some wellbore zones in the longer fractures never break, and in these fractures their widths around the tip zones are larger than those around the wellbore zones.
Insights from the simulations are helpful to understand the mechanisms leading to the unsatisfactory production performance of the fractures, and the simulator can therefore be used to optimize staged hydraulic fracturing.