bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture Height Growth Study: Cooper Basin Probability Analysis
Authors: Griffiths James 
Published: October 2018

Abstract
A probability graph was developed to describe height growth potential when performing hydraulic fracture stimulation operations in the Cooper Basin, Central Australia. This graph has led to improvements in setting completion strategies.
Multiple data sources were used to define the probability graph, including proppant tracers, microseismic, downhole tiltmeter data as well as pressure interference and production data. Each dataset has known uncertainties, so the empirically derived probability graph has an intrinsic range of uncertainty.
The observed data shows instances of fracture propagation across changes in lithology which were previously thought to be highly confining. In other instances, field data closely matched model predictions. Likewise, the observed data indicates that typical levers used to induce or reduce height growth (such as fluid viscosity, pump rate and job size) may have limited influence. These insights led decision makers to question the validity of deterministic fracture models.
This study highlights that fracture height growth predictions should carry a range of uncertainty. An appreciation of this range has proven beneficial by fostering ‘what-if’ discussions during the project planning phase. The derived probability graph can be used to run sensitivity analyses to determine the optimal path when several completion methods are available.
This graph has proven to be an informative and practical tool for use in the Cooper Basin by promoting deeper thought and collaboration amongst stakeholders. Similar tools could be developed to characterise fracture height growth within other petroleum basins.
Produced Water Reinjection at Wellpads: Leverage Terminal Liquid Handling & Accelerate Oil Production from MBA Fields
Authors: Mehta Nirav , Ray Rimjhim , Kapadia Gautam 
Published: October 2018

Abstract
Oil, water and gas separation at wellpads with improved technology and compact design has significant advantage for increasing liquid handling from group gathering wellpads and accelerating oil production from fields. Cairn, Oil & Gas vertical of Vedanta Limited is the Operator of RJ/ON block in India with major fields Mangala (M), Bhagyam (B) and Aishwariya (A). Mangala field (75% of MBA production) is the largest onshore oil discovery in India and Bhagyam-Aishwarya fields together contribute to ~25% of the total MBA production. The MBA fields are on water + polymer flood and gradual increase in water production is challenging to process the same oil production volumes. Future field development plans in these fields requires debottlenecking of liquid handling constraints.
The current paper depicts the fast track modifications planned in various fields and its implementation carried out in Aishwariya field which was limited for produced fluid handling due to capacity constraints at the centralized processing well-pad 8 (AWP-08). These modifications were aimed towards localized produced water treatment and reinjection of 30,000 barrels per day (bpd) into the existing injection manifold at Aishwarya Wellpad. In the first stage, produced water is separated from 3,000 ppm to 300 ppm OIW and in second stage from 300 to &lt;100 ppm OIW with &lt;5 ppm TSS. The existing vessels were retrofitted and modified in field with internals like inlet device, calming baffles, coalescing pack, overflow weir and oil bucket. This enabled additional residence time suiting the given fluid characteristics and efficient separation of the produced fluids. This resulted in accelerating oil production from the field by ~2,000 bopd by opening more shut-in wells and leveraging terminal liquid handling capacity. And with the future ESP upsizing and more infill wells coming online, there is further potential to gain additional oil upto 3000 bopd. The execution of Project commenced in Sep-17 and was commissioned in Dec-17 in a record 3 months’ time period including engineering which helped in monetizing early oil production benefit. Based on the success of the local pad separation in Aishwariya field, similar scheme is planned to be implemented in Mangala & Bhagyam wellpads and other small fields with high water production.
Intelligent Waterflooding Development of High-Permeability Reservoirs at the Late Development Stage
Authors: Jia Deli , Guo Tong , Pei Xiaohan , Zhang Jiqun , Ye Qinyou , Jin Xian'gao , Tang Xiaohong 
Published: October 2018

Abstract
In China, the initial development program was "early zonal water injection" for the reservoirs with insufficient natural drives and low formation-saturation pressure differential. At present, the oilfields have successively been progressing into the late development stage with high water cut. Especially in high-permeability reservoirs, water fingering through a single layer results in poor development response. The objective of this paper is to efficiently control invalid water cycling and realize a smooth flooding profile. A technology for whole-process monitoring and controlling in zonal injection has been developed for waterflooding reservoirs based on cable-controlling approach. This technology can constantly monitor real-time flowrate, cumulative volume injected, tubing pressure and casing pressure, as well as intelligently adjust the injection rate according to the allocation in the development program, thereby realizing fine zonal injection. As a demonstration, a typical block characterized by the high permeability (~100 mD in average) and being at the late development stage with high water cut (96.8%), was chosen to conduct the follow-up study and evaluate waterflooding efficiency of high-permeability reservoirs.
There are 54 water injectors connected to 98 oil producers in the demonstration block. The data for one consecutive year upon implementation of the technology were collected and then analyzed. The analysis results illustrated that the water absorption profile was improved and the water fingering was efficiently controlled. The monthly rising rate of the composite water cut in the demonstration block decreased from 0.1% (value before the implementation) to 0.02%, and even to −0.027% in some individual well groups (which means the composite water cut was reduced); 77.5% of sandbody thickness in some individual wells has been producing, compared to 50.7% before the implementation, achieving remarkable effect. As can be seen, this technology is of great guiding significance for waterflooding development of high-permeability reservoirs at the late development stage with high water cut.
Development and Application of Key Equipment of CO2 Waterless Fracturing
Authors: Zheng Lichen , Meng Siwei , Chen Shi , Yang Qinghai 
Published: October 2018

Abstract
Water is essential for energy exploitation, and moreover the contradiction between water resources and energy recovery seen in China is more severe than those in other countries. Given this, CO2 waterless fracturing, which improves the production and recovery factor of an individual well and meanwhile serves for water preservation and CO2 underground storage, can contribute to the sustainable development of China's oil industry.
The continuity and reliability of equipment is a key technical aspect for the successful waterless fracturing, in which the operation is required to be done in a sealed, pressurized environment during the whole workflow, and the proppant-carrying capability of fluids is low. Therefore, strict requirements are raised up upon the equipment. On the basis of the dynamic fluid balance combined with the fluid phase evolution during the whole construction workflow and its effects on stimulation treatments, this paper optimized the design of key construction equipment, such as CO2 storage tanks, booster pumps, sealed blender trucks and fracturing pump trucks.
Major improvements can be concluded as: 1) the vertical tank is used for the sealed blender, which enhances the control stability of sand supply process jointly by the pressure difference regulation and auger; 2) booster pump unit with high pump-rate capability are included in the system for liquid supply and fluid phase control; 3) the liquid supply combines the mobile transport tanks and fixed storage tanks to increase the liquid supply capability; 4) the fracturing system is equipped with eight special fracturing pumps for waterless fracturing, fulfilling the construction requirement of 20,000 hydraulic horse power. The whole equipment system has treatment capability of available pump rates up to 12 m3/min, sand volume of 27 m3 and CO2 injection of 1500 m3. In 2017, this equipment system was used in waterless fracturing for six times, with a maximum proppant input of 23 m3. Both the liquid and sand supply processes are found stable, and the production gain after stimulation is considerable.
It is estimated that in tight reservoir, oil production brought by 1 unit volume of CO2 equals to that of 2.4 unit volume of water-based fracturing fluid. Providing that the average CO2 injection of waterless fracturing wells is 630 m3, a single well can save 1512 m3 water resource. This equipment system fully meets the requirement of fracturing in vertical and horizontal wells of unconventional resources, and can effectively support the further development of the waterless fracturing technology.
A Human-Computer Hybrid Approach to Offshore Field Development: Combining Virtual Reality Aided Design with Stochastic Optimization
Authors: Almedallah Mohammed , Walsh Stuart , Lau Tsan Hou 
Published: October 2018

Abstract
Offshore oil and gas field developments are capital-intensive projects that require extensive facilities to drill, produce and transport the hydrocarbon from the reservoir to the processing plant. Determining the site, number and size of these facilities are amongst the most important decisions impacting a project's success. Here, we present a novel strategy to assist in these decisions by combining a stochastic optimization routine with a Virtual Reality (VR) Aided Design. The model uses a discrete-network optimization algorithm that employs a Monte Carlo Markov chain to explore feasible configurations that minimize the development's investment. It integrates the optimization with a state-of-the-art VR environment to allow the engineer to both monitor the progress of the optimization and help guide the field development in real time.
We present results illustrating how the approach can be employed in field developments to connect well targets to processing facilities. The model determines the optimum location, size and number of offshore well-head platforms, tie-in facilities, well paths and pipeline routes. It incorporates critical technical considerations for the design of drilling paths (e.g. dog leg severity) and surface facilities (e.g. water depth). The model has been applied to real data from offshore field developments in the North Sea and the Gulf of Mexico. Results including the investment value and optimum configuration are shown and supplemented with graphics from the VR environment. The VR technology enables a novel approach to optimize the development. The immersive platform lets the user not only visualize the field, it is also capable of providing real-time interaction with the computer-generated design. This allows the integration of engineering intuition and experience to enhance the development and eliminate infeasible or unfavorable configurations.
Application of Novel Predictive Analytics for Data Allocation of Commingled Production in Smart Fields
Authors: Chia Mabel Pei , Yakup M Hamzi , Tamin Muhammad , Surin Nicholas Aloysius , Mazzlan Khairul Akmal , Rinadi M , Hassan A Azim 
Published: October 2018

Abstract
This paper details out the application of a predictive analysis tool to ‘S’ Field's commingled production, aiming to enhance production allocation and reservoir understanding without the need of well intervention and a reduced frequency of zonal rate tests and data acquisition.
Allocation of the production data to its respective reservoirs is performed via a novel Multi-Phase Allocation method (MPA), taking into account the water production trending evolution derived from relative permeability behavior of oil-water in each reservoir to compute flow rates for liquid phases over time. The precision of the derived rates is constrained by actual zonal rates tests through Inflow Control Valves (ICVs). This method will be cross referenced against ‘S’ Field's existing zonal rate calculation algorithm, utilizing input data from well tests results and real time pressure and temperature data.
The MPA method demonstrates improvement in the allocation of production data as compared to the conventional KH-methodology as MPA takes into account the water cut trending between reservoirs. Leveraging on ICVs to obtain actual zonal rate measurements, this greatly reduces the range of uncertainty in the allocation process. MPA derived production split ratios closely match the split ratios derived from the ‘S’ Field's existing zonal rate calculation algorithm, which utilizes input data from well tests results and real time pressure and temperature data from down hole gauges.
It is observed that the usage of actual measured zonal rate tests reduces the range of uncertainty of the MPA data.
A combination of novel multi-phase deliverability models coupled with smart field technologies such as intelligent completions and real-time surveillance and analysis tools will increase the accuracy of the back allocation of multi-phase production data in commingled reservoirs.
In-House Software Development for Gas Production Optimization: A South East Asia Perspective
Authors: Wongkamthong Chayut , Wongpattananukul Kongphop , Suranetinai Chaiyaporn , Vongsinudom Varoon , Ekkawong Peerapong 
Published: October 2018

Abstract
Several gas fields in South East Asia share some common traits among them, obviously on their geological features but also on their complex field operation. With a large number of small gas accumulations spreading across a large area with high degree of lateral compartmentalization, production from these fields are usually accomplished by hundreds of wells through multi-branches field networks. The scope of this paper is to present the challenging journey of the company's in-house innovative methodology which resulted in the development of a robust software to address the above challenges. The main objective of the software is to optimize field production under numerous constraints present in these fields.
With the target to optimize field production and enhance predictive capability, the company integrates the experiences from operating several fields and proposes an innovative approach to tackle these field management challenges. The resultant software optimizes and solves the network calculation by simplifying and formulating the production network into a system of linear equations, then applying optimization techniques as large-scale simplex and mixed-integer linear programming algorithms, to search for the best production scheme while taking user-selected objective function into consideration. The workflow was developed using MATLAB optimization toolbox to work in conjunction with a familiar Excel-formatted input. Moreover, with the incorporation of the Decline Curve Analysis (DCA), it is also applicable for generating long term production forecast. The tool was further combined with Production Data Management System (PDMS) to provide a more efficient automated workflow. It was used to maximize condensate production in Arthit field, where the main constraints are to capture the production loss from CO2 removal unit and to limit mercury concentration in sales condensate. While, in Zawtika field, the application exploits quadratic programing to minimize the sum of gas production rate square hence controlling wells to produce at optimal rate, mitigating sand production problem.
In this paper, successful implementation examples and benefits gained will be discussed. It ensures that the condensate production in Arthit field is kept at optimal level compared with about 91% efficiency when subjected to conventional practices while, in Zawtika, applying the workflow and operation resulted in dramatically lower sand production problem. For future forecast, a look-back study was performed to make sure that the method of calculating future potential is accurate. Not only does this new tool provided a more efficient way for the teams to manage their assets but, more importantly, it also helps to save costs by reducing man-hours through its rapid computation.
Systematic Approach in Extending Liquid Loaded Offshore Gas Wells Production in Natuna Sea with Partial and Full Wellbore Water Shut Off: Case Study and Method Selection
Authors: Praditya Yusuf Alfyan , Satiawarman Anugerah , Nurrahman Fahmi , Medianestrian Medianestrian , Rochaendy Risnawan 
Published: October 2018

Abstract
Wells which produce dry gas reservoirs usually have low bottomhole pressure. But in many instance liquid is associated with the produced gas, it can come from the liquid in reservoir or condensed production liquid. When more liquid is introduced into the wellbore, the pressure gradient along the wellbore is higher. The increased liquid fraction creates higher backpressure on the reservoir delivering gas. In high pressure gas reservoir the presence of liquid can occur in several degree of bubble and slug flow; in depleted gas reservoir the liquid can kill the well as the gas does not have enough transport energy to lift the liquid. At the point when the gas velocity is insufficient to carry out liquid, liquid will start to drop and accumulate in the bottomhole creating a restriction on the gas flow path, the phenomena is called liquid loading.
This paper presents success case studies from Premier Oil Indonesia in handling and reactivating four liquid loaded gas wells in Natuna Sea offshore operation. Wellbore configuration and facility limitations in offshore operation (e.g. maximum deck load capacity, water handling capacity and crane capacity) create more complexity of the method selection in comparison to onshore operation. There are many gas well deliquification methods available in the industry, but not in instance that each method is appropriate for all conditions. The case studies presented in this paper provide description of how Premier Oil Indonesia screened several available gas well deliquification methods in the industry and came up with the water shut off proposal as the best and most proper method for its wells. The understanding of liquid loading indication, liquid source identification and operational details of gas well deliquification methods are the most important factors to determine the most effective and cost efficient method to handle liquid loaded wells. This paper also presents a general guideline in selecting the best gas well deliquification method for some specific cases under several operational conditions for onshore and offshore operations.
Improved Sand Management Methodology Application in Mature Field
Authors: Tugimin M Azri , Kamat Dahlila , Baghdadi Faical , Gupta Anish , Mohammad Azili Ammar , Mohamed Hanafi Muhammad Mukrim , Meza David 
Published: October 2018

Abstract
Sand Monitoring workflow was introduced in R field to manage and minimize the risk that sand production poses to the production facility by monitoring the sand production and its resulting erosion rate, and raise alarm immediately when these conditions violates the allowable threshold. The workflow serves as an enabler to the sand management process that are put in place at the field. By leveraging the automation from IO and complement it with additional processes, we came up with a holistic approach that is used to minimize the risk to the production facility. The defined Sand Management methodology starts with the automated workflow processing. The workflow utilizes data from field sensors and processes them to conduct risk assessments, and some mathematical calculation that are based on proven correlations. Based on these processes, the workflow will generate output of sand production risk assessment, calculated erosion rate, estimated remaining pipe thickness as a result from the erosion rate and critical drawdown monitoring.
To complement the output from the workflow, additional processes that utilizes the outputs are introduced as part of the sand management process. Some of these additional processes are: Correlation calibration by comparing the estimated pipe thickness from the workflow against computerized radiography or unit thickness manual measurement.Conduct Sand Depositional modelling at the high-risk location identified from the workflow to optimize sand handling capacity and monitoring.Extend the monitoring by utilizing network modelling software to assess the erosional risk from interlink of pipelines between jackets.Choke health monitoring and estimation based on choke CV and modelling.
The sand monitoring workflow has increased personnel efficiency by automating repetitive and tedious work and give out the result in an easily interpreted manner. The automated alarm has been proven to be useful in proactively engaging operations to tackle the problematic matter. Production interruption related to sand production has been effectively reduced by 50% after the implementation of the new Sand Management methodology.
The introduction of the workflow into the new methodology uses marginal cost, but maximizes the return on existing asset through the realization of their production potential, as well as proving on how multidisciplinary integration and collaboration between operator and the service company can be successful in a mature field despite the risk associated.
A New Method to Predict FWL Based on Porous Plate Capillary Pressure and Resistivity Relationship
Authors: Tan Willy 
Published: October 2018

Abstract
The proposed method in this paper estimates FWL based on the relationship derived between resistivity, capillary pressure, water saturation and permeability. Since porous plate experiment provides simultaneous resistivity index (RI) and capillary pressure at identical saturation state, one can combine these two pieces of information (Pc-vs-Sw and RI-vs-Sw) and produce a new Pc/Rt-vs-Sw plot. Interestingly, Pc/Rt-vs-Sw exhibits an exponential behavior which can be described using an exponential function with fitting coefficient a, b, c and d. Once these fitting coefficients are obtained for each individual plug, they are correlated to petrophysical property such as permeability. After all the relationships are established on core plugs, the log-based capillary pressure (Pc, laboratory condition) can be estimated from the resistivity, water saturation and permeability logs. For application in oilfields, this laboratory condition Pc has to be converted to reservoir condition Pc. The reservoir condition Pc is interpreted as reservoir condition buoyancy pressure (Pb). We then subtract this reservoir condition Pb from the hydrocarbon pressure established from the formation tester. Finally, a water line with a known gradient (eg: 0.433 psi/ft) can be drawn across the predicted log-based buoyancy pressure. FWL is located at the intersection between this ‘pseudo’ water line and hydrocarbon line established from formation tester.