bluuebunny/crossref_metadata_2025 huggingface dataset:
Flow Assurance Challenges for China’s First Deepwater Gas Field Development in South China Sea
Authors: Lau Lawrence Khin , An Kun , Tang Xian Di , Luo Fei Jian , Yang Yang , Zhao Wei Qing
Published: November 2020

This paper elucidates the key flow assurance challenges for China’s first National Deepwater gas field development in South China Sea and the facilities design forming the overall flow assurance management strategy. The discussion covers early stage feasibility studies through current stage of project execution. In addition, the finding of flow assurance analysis serves as key input for start-up and commissioning guidelines as well as operating procedures.

The development consists of a semi-submersible, with the Eastern and the Western loops spanning more than 40 km of Subsea Production System (SPS). Due to long subsea tiebacks, integrated flow assurance analysis is rolled out to ensure comprehensive risks analysis and active risks management. In particular, key challenges associated with typical Deepwater characteristics such as high pressure and low temperature are actively managed. With design water depth of more than 1500 m and more than 10 Deepwater subsea production wells, robust flow assurance management strategy is required from early activities such as well unloading, well test, pre-commissioning, first gas, through late life decommissioning.

Integrated approach is implemented for overall system thermohydraulics analysis, which is used as basis for key flow assurance assessments, including but not limited to management strategy for hydrate, scales, erosion, and slugging. Detailed management strategy and philosophy are discussed in the main body of this paper. Overall chemical management strategy, for instance, is fully optimized to reduce Health, Safety, Security and Environment (HSSE) impact, coupled with sufficient safety margin to ensure minimum downtime.

Through integrated flow assurance analysis, all key risks are identified and actively managed. This shows the importance of integrated flow assurance approach to ensure overall project safety and integrity. More importantly, overall optimization can be successful rolled out when the field is in production. This serves as a positive lesson learned for future Deepwater development in South China Sea.
Miscible CO2 Flooding Simulation with a Compositional Model in Middle East Carbonate Reservoir
Authors: Wu Shuhong , Fan Tianyi , Zhao Lisha , Peng Hui , Wang Baohua , Ma Xuesong
Published: November 2020

CO2 injection has proven to be a promising technology in enhancing oil recovery in low-permeablility carbonate reservoirs, especially in miscible flooding. How to demonstrate near-miscible/miscible mechanisms and their influence on production performance is a difficult issue to deal with in a compositional simulation. In this paper, considerable research has been conducted on compositional models, especially miscible gas flooding models, by identifying the near-miscible/miscible state and its influence on relative permeability.

This paper describes a multi-component, three-phase, compositional model for simulating miscible CO2 flooding problems. An EOS equation is constructed for phase equilibrium and property calculations. Gibbs stability model is developed to determine whether a hydrocarbon mixture at a particular temperature and pressure is more stable in a single-phase state or in a two-phase state. An interfacial tension (IFT) weighted relatively permeability model is developed to calculate the relative permeability in a near-miscible state. With the help of the Gibbs and Kr models, miscible CO2 flooding in a carbonate reservoir is simulated to evaluate the miscible and immiscible state and demonstrate the production performance.

The Gibbs stability model determines the tangent plane of the Gibbs energy surface at the mixture composition and parallel tangent planes at possible incipient phase compositions. If any of the parallel tangent planes lie below the tangent plane of the mixture composition, a two-phase state will exist. The simulation shows that a Gibbs stability model in CO2 injection can identify whether the hydrocarbon mixture (oil) and CO2 at reservoir pressure and temperature is in one phase state (miscible) or in a two-phase state (immiscible). The IFT weighted Kr model determines an interpolation between immiscible and miscible states using a weighting function, which is a function of IFT with a specified critical gas/oil IFT to control the contribution of the near-miscible effect on kr. The compositional simulation shows that CO2 becomes miscible with a hydrocarbon mixture under the condition of CO2 multi-contact with the hydrocarbon mixture in the reservoir pressure and temperature. Three areas exist between the injector and the producer which are the immiscible area (IFT: about initial value), near-miscible area (IFT: 0.5~2) and miscible area (IFT: lower than 0.5). The residual oil saturation of the miscible CO2 flooding area is around 5%. Oil recovery is enhanced compared with the previous hydrocarbon gas injection.

CO2 injection represents a promising technology to improve production performance and to enhance oil recovery for the carbonate reservoir mentioned in the paper.
Inversion of Advanced Full Waveform Sonic Data Provides Magnitudes of Minimum and Maximum Horizontal Stress for Calibrating the Geomechanics Model in a Gas Storage Reservoir
Authors: Pallikathekathil Zachariah John , Yang Xing Wang , Hafezy Saeed , Puspitasari Ratih , Harris Rodney I. , Sutton Jacqueline T.
Published: November 2020

In 1D Geomechanics projects, calibration of stress is extremely important in the construction of a valid Mechanical Earth Model (MEM). The minimum horizontal stress data is usually available from LOT (Leak-off test), XLOT (Extended Leak-off test), Open hole stress tests, or cased hole Mini Fall off Test (also called Diagnostic Fracture Injection Test – DFIT). These traditional measurements have a few deficiencies.

This paper presents an application to a gas storage field, where stresses are derived from a newer unique approach where the radial variation of acoustic velocity from advanced dipole sonic logging tool is inverted to obtain stress. These derived stresses are then utilized to calibrate the 1D MEM for the gas field. This approach addresses some of the deficiencies of traditional approaches of deriving stress magnitudes. The characteristics of this approach are:Both the minimum horizontal stress (Shmin) and maximum horizontal stress (SHmax) are obtained. Traditional approach provides a value for Shmin only.These measurements are obtained in reservoir zones at multiple depth intervals. Traditional approaches provide a measurement at one depth only.This method is applicable to all formations that are acoustically stress sensitive.This method is relatively more cost effective as compared to traditional approaches where rig time is a premium considering that advanced sonic logs are routinely run for other applications as well.

The sonic data was processed to derive a dispersion plot (velocity versus frequency). From this plot, a plot of velocity versus radial distance is derived. As Kirsch equation provides a radial variation of the stress with distance for a hole drilled in a uniform stress field, and variation of stress translates to variation with velocity, a parametric inversion is utilised to derive the stress.

In this gas field, no LOT or XLOT were available. However, the advanced dipole sonic logging tool was recorded in a well recently drilled and some of the formations were found to be acoustically stress sensitive as observed from the dispersion plot. Therefore, this inversion technique was applied and Shmin and SHmax were obtained that were extremely useful to calibrate the 1D MEM.

This technique is unique in the industry and complements existing methods to obtain stress measurements for 1D MEMs where stress measurements are either not available or expensive to obtain. This method is not widely used. The authors hope that this paper will illustrate how this method was used in this gas field and encourages other users to investigate the application of this method in their fields, when traditional data is limited.
Regulatory Challenges and Opportunities for Optimising Petroleum Resource Stewardship in Offshore Australia
Authors: Miranda John , Hamp Roland , Cocodia Erebi , Filbay Nicole
Published: November 2020

The challenges and insights presented in this paper provide a unique case study of Australia’s evolving offshore petroleum industry from a regulatory lens. It documents how a regulating agency’s unique perspective can identify opportunities to optimise recovery, contribute towards improvements in good oil practice and ultimately adapt to the changing requirements of industry.

This paper sets out the regulatory landscape, as well as the challenges that exist in managing an innovative, adaptive and evolving offshore petroleum industry. Australia’s offshore resource stewardship strategies must now respond to a more established, maturing, more ‘crowded’ and dynamic petroleum landscape. This challenges regulators to be increasingly responsive, adaptive, continuously improve practices and be well-informed regarding global trends, such as those affecting mature provinces. Opportunities to exchange ideas, collaborate and incorporate key learnings from other offshore regulatory regimes are considered key enablers towards achieving these goals.

Australia’s maturing petroleum provinces are impacted by long distances, (relatively) low infrastructure density and greater water depths; whilst increasingly challenged to integrate smaller, deeper and economically marginal resources. Conversely, emerging/recently established production areas are now facing an increasingly dense infrastructure landscape with multiple potential development pathways. In contrast to traditional system-wide blanket or "title-by-title" approaches (particularly with respect to optimal use of existing infrastructure), effective resource stewardship requires an increased level of consideration of "area" or "regional" developments. A more responsive and adaptive approach, which fosters collaboration and effective dialogue between the regulator and industry, improves regional understanding and contributes toward optimum resource recovery (via lower life-cycle costs and accelerated production opportunities).
Experimental Investigation on EOR and Flowback Rate of Using Supercritical CO2 as Pre-Fracturing Fluid in Tight Oil Reservoir
Authors: Li Lei , Su Yuliang , Chen Zheng , Fan Liyao , Tang Meirong , Tu Jiawei
Published: November 2020

Fracturing is the necessary means of tight oil development and the most common fracturing fluid is slickwater. However, the loess plateau of ordos basin in China is seriously short of water resources. Therefore, the tight oil development in this area by hydraulic fracturing is extremely expensive and bad for the environment. In this paper, a new method using CO2 as pre-fracturing fluid is applied in hydraulic fracturing. This method can give full play to the dual advantages of supercritical CO2 characteristics and mixed water fracturing technology while saving water resources at the same time. On the other hand, this method can reduce reservoir damage, change rock microstructure, and significantly increase oil production after full interaction with formation fluid, which is a development method with broad application prospect.

In this work, the main mechanism, the the system energy enhancement, and flowback rate of CO2 as pre-fracturing fluid are investigated. Firstly, the microscopic mechanism of CO2 fracturing was studied, and the effects of CO2 on pores and rock minerals were analyzed by NMR test, XRD analysis and SEM experiment. Secondly, the high pressure chamber reaction experiment was conducted to study the distribution and existence state of supercritical CO2 in the multiphase fluid during the full-cycle fracturing process. Finally, four injection modes of CO2 injection experiments were designed to compare the pressure increase, production enhancement, and flowback rate of CO2 and slickwater, so as to optimize the optimal CO2 injection mode and the optimal injection amount of CO2 slug.

The results show that supercritical CO2 can increase the porosity of rocks by dissolving calcite and clay minerals (illite and chlorite) that gather around the pores according to the changes of pore size and rock composition before and after CO2 action. Supercritical CO2 injection increases the saturation pressure, expansion coefficient, volume coefficient, density, and compressibility of crude oil, which are the main mechanisms of fracturing energy increase and production enhancement. After analyzing the four different injection modes tests, the optimal one is to first inject CO2 and then inject slickwater for fracturing. The CO2 slug has the optimal value which is 0.5 pore volume in this study.

In this study, supercritical CO2 is used as the pre-fracturing fluid, providing a new idea for the stimulation of tight oil. Experimental studies have proved the pressure increase, production enhancement, and flowback potential of CO2 pre-fracturing. The application of this method is of great significance to the protection of water resources and the improvement of fracturing effect.
A Comparative Review of Production Logging Techniques in Open Hole Extended Reach Wells
Authors: S Duthie Laurie , A Saiood Hussain , A Al-Anizi Abdulaziz , A AlGhamdi Talal
Published: November 2020

Successful reservoir surveillance is a key component to effectively manage any field production strategy. For open hole extended reach horizontal wells, including some wells over 30,000 ft in length, the challenges to successfully deploy real-time logging tools are greatly magnified. This is further complicated by constraints in the completion where Electrical Submersible Pumps (ESP's) are installed. A comparative review of the latest technologies and methods available to overcome these challenges will be explored.

The challenges are formidable and extensive; logging these extreme lengths in cased hole would be difficult enough, but are considerably exaggerated in the open-hole condition. The logging run in open hole must also contend with increased frictional forces, high dogleg severity, washouts and an increased well bore rugosity. The main challenges to achieve the logging objectives in open hole extended reach wells, are 2-fold, namely;

To log the entire open hole section and reach the Total Depth (TD) of the well. To obtain high quality data from the logging tools, despite the adverse downhole environment.

To achieve these 2 main objectives, a comprehensive approach is taken while designing the logging operation. The choices available to deploy the logging tools are mainly on electric-line cable with an electric powered tractor or on coil tubing with a hydraulically powered tractor. The most common type of log performed in these extended reach wells is a production log to measure multi-phase inflow contributions. To improve the success rate of the logs, a number of initiatives have been implemented, including deployment of custom designed coil tubing tractors and state of the art wireline tractors. The logging tools and job programs are adapted based on the results of simulations, accounting for many variables, including the completion, well type, deviation and target depth.

The ability to successfully log these extended reach wells cannot be understated, reservoir simulations and management decisions can only as good as the quality of data available. Some of the advantages of drilling mega reach wells such as increased reservoir contact, reduced footprint and less wells drilled will be lost if adequate reservoir surveillance cannot be achieved. To meet the key objectives, creative solutions including designing and upgrading the best fit for purpose technologies are applied for the extended reach wells. These steps taken not only improve the overall logging performance, they can also result in cost savings by avoiding multiple unsuccessful logging runs.
An Assessment of the Application of Propellant Enhancement to Conventional Wells
Authors: Campin David
Published: November 2020

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

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 < n < 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

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

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

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

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

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

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

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.
Development of New Degradable and Swelling Diverting Agent for Use in Low Temperature Hydraulic Fracturing Treatments
Authors: Sato Ken , Shinohara Kenji , Furui Kenji , Mandai Shusaku , Ishihara Chizuko , Hirano Yasuhiro , Taniguchi Ryosuke
Published: November 2020

It has been reported that hydraulic fracturing treatments with smaller cluster spacing and larger fracturing fluids volumes yield better production performance in Permian Basin, Bakken, and Eagle Ford. Degradable diverting agents can play an important role as temporary plugging materials for multiple, tightly-spaced fracturing operations. However, applications of degradable diverting agents are often limited to moderate to high reservoir temperatures. In this study, a new degradable diverting agent is developed for use in low temperature reservoir applications.

Butane-diol vinyl alcohol co-polymer (BVOH) which has controllable water solubility is evaluated as diverting agents for hydraulic fracturing treatments. Using a high pressure-high temperature filtration apparatus, filtration properties of BVOH diverting agents are measured for various powder-to-pellet ratios under a range of temperature conditions. Filter media with 1 to 3 mm width slots, that simulate fracture openings, are used for the filtration test. The filtrate properties are evaluated based on spurt losses and filtration coefficients for quantitative evaluation. An analytical diverting agent model that considers swelling of the polymer in water is also developed for evaluating the filtration process of multimodal particles.

The experimental results presented in this work indicate that the degradable BVOH materials can be used as effective plugging agents for fracture-like narrow slits. Based on spurt losses and leakoff coefficients obtained under different powder-to-pellet ratios and temperature conditions, the performance of the diverting agents is quantitatively evaluated. The optimum powder-to-pellet ratio for BVOH materials are determined to be 80 to 20. The experimental results also reveal that the degree of BVOH crystallinity provides a dominant effect on the solubility of BVOH powder. The test results also indicate that the diverting agent plug properties started degrading under the temperature greater than 140°F as designed. The BVOH diverting agent developed in this work provides effective diversion effects under low to moderate temperature conditions (e.g., 80 to 100°F). The analytical plugging and bridging model developed in this work, which takes into account swelling properties of the polymer, show very good matches to the experimental results.

The degradable diverting agent developed for low temperature applications improve operational efficiency and economics of multistage hydraulic fracturing treatments in shallow reservoirs and operations where immediate fracturing fluid flowback is required. The plugging and bridging model with bimodal particle system developed in this study helps stimulation engineers select and optimize diverting agent material types, particle size distribution, and diverting agent concentration for various well, stimulation, and reservoir conditions.
Novel High-Effective Component for Acidizing Corrosion Inhibitors: Indolizine Derivatives of the Quaternary Quinolinium Salts
Authors: Yang Zhen , Wang Yefei , Finšgar Matjaž , Hu Huayou , Wu Jiajia , Zhan Fengtao , Sun Shuangqing , Ding Wengang
Published: November 2020

Acidizing is a widely used method for the well stimulation and Corrosion inhibitors (CIs) are essential in acidizing fluid to mitigate corrosion of metallic equipment. This calls for high-effective CIs as the demands for oil and gas still increases. This paper introduces several new protective indolizine derivative compounds with remarkable inhibition effectiveness under high-temperature acidizing condition. The indolizine derivatives were obtained facilely through the cycloaddition (at about 80 °C, alcohol as a solvent) procedure from the conventional quinolinium salt. Chemical structures of the derivatives were confirmed by instrumental analysis methods including NMR, MS etc. The corrosion inhibition properties of the indolizine derivatives were investigated and evaluated by weight loss test, electrochemical methods (Tafel curve and EIS), in comparison with their quaternary quinolinium precursors. Corrosion inhibition behavior of the derivatives in acid was simulated by DFT study. The thermodynamic aspect of the inhibition were also investigated. Experimental results showed that very low dosage of indolizine derivatives exhibit excellent inhibition efficiencies for the N80 steel in corrosive medium. Apart from the good solubility and thermo-stability in aqueous acid solution, the indolizine derivatives even showed eco-friendly advantages by presenting a much lower EC50 values than the other CIs. Compared with the conventional acidizing CIs, the composite indolizine derivative derived inhibitor mixture can dramatically mitigate the corrosion even at low amount of the mixture added, especially for those tests conducted at the bottom-hole elevated temperatures. The amazing inhibition of novel indolizine derivative with organic or inorganic components reveals that the mixture could be utilized as new effective CI for acidizing in concentrated hot acid. The inhibition of series traditional quinolinium salts would get greatly improved after they have get converted into the corresponding indolizine derivative inhibitors, which provides enlightening thoughts for developing novel high-effective CIs. The use of these compounds may offer a creative new choice for strong acid medium corrosion in petroleum engineering and showing good prospects in replacement of the current main components of acidizing CIs in the near future.
Pressure Transient Analysis in Fractured Horizontal Wells with Three-Dimensional Flow: Case Study
Authors: Dong Peng , Chen Zhiming , Yi Xinbin , Wang Tianyi , Liao Xinwei , Chu Hongyang
Published: November 2020

Pressure transient analysis in fractured horizontal wells in unconventional reservoirs has received much attention in last two decades. A large number of microseismic data showed that many hydraulic fractures do not actually penetrate the entire formation, which means that 3D flow into the hydraulic fractures should be considered. However, there is limited work on analytical method based well-testing models for fractured horizontal wells with 3D flow. To improve this situation, a semi-analytical model for the horizontal well with partly-penetrated multi-state fractures are developed with considering 3D flow, based on fracture discretization. The new model proposed in this paper can describe more complex 3D flows in the multiple hydraulic fractures.

With flow regimes analysis and field application, it is found that the pressure derivative curves of fractured horizontal wells with 3D flow are complex. The most obvious feature of the flow regimes is that the curve appears to drop after the linear flow. It behaves like a second "hump" occurs in the pressure derivative curve. This is due to the fact that fractures do not penetrate the formation completely, and a pseudo-spherical flow occurs at this stage. The pseudo-spherical flow is more obvious when the fracture height is small or the fracture is short. Evaluated results from field application are basically consistent with the overall understanding of the MH shale oil reservoirs, which demonstrates the reliability and practicability of the proposed model. The evaluated fracture conductivity is less than an ideal value, because the fracture conductivity declines rapidly with the high reservoir pressure. This work helps to better understand the pressure transient behavior and to facilitate fracture evaluation in the unconventional reservoirs.
Automated Pattern Recognition as a Temporary Replacement for Downhole Gauges
Authors: Lyall John , Watt Andy , Murphy Chris
Published: November 2020

Automated pattern recognition with basic, high-level coding can be readily applied to petroleum production surveillance to reduce the impact of equipment failure. Machine learning is an application of regression techniques that range in complexity from simple linear regressions to convolutional neural networks. This paper outlines a machine learning based solution that was developed for a common petroleum engineering problem.

A temporary proxy for downhole pressure measurements was developed after gauge failure on an offshore gas production well. A solution was found in the machine learning space by applying multivariate linear regression to represent relationships within the production system. The workflow presented is based on Python code using the open source SKLearn library. Readers should carry out their own independent assessment of the approach outlined in this paper (including the model development procedure pseudo code set out in Appendix B and Python code example set out in Appendix C) in the context of their own specific requirements and circumstances before deciding to use any aspect of the approach (or Python code).

The method uses available production data (known conditions of pressure and temperature from the wellhead and further downstream, choke settings and well total mass flow rates) to predict an unknown downhole pressure. The failure of a downhole gauge was simulated by removing the downhole data from the dataset at a certain point in time. The machine learning model was trained using 19 months of well production data. The nine months that follow was then entered under gauge failure conditions (with downhole data removed), to predict downhole pressure from other production data. The result was a downhole pressure prediction within 0.2% (40 kPa) of the actual gauge measurement up to nine months after the simulated gauge failure.

The prediction was compared to downhole pressure estimations that were calculated with a conventional physical model. The machine learning model outperformed the conventional physical correlation over the test period. The model was validated as an adequate short-term replacement for downhole pressure measurement for an offshore gas well. The solution delayed disruption to the management of reserves, enabled the continuation of production forecasting and postponed subsea intervention.

This paper also provides a foundation for assisted trend analysis, in which a gauge that is identified as drifting from the long-term trend can aid in the detection of physical changes such as water breakthrough.