bluuebunny/crossref_metadata_2025_split huggingface dataset:
CO2 Injection for Improved Recovery in Tight Gas Condensate Reservoirs
Authors: El Morsy Mahmoud , Ali Samad , Giddins Marie Ann , Fitch Peter 
Published: November 2020

Abstract
Condensate banking is one of the main challenges facing operators of gas condensate reservoirs. Different techniques have been used over the years to improve well deliverability in condensate reservoirs, including gas recycling, gas injection, matrix acidization and hydraulic fracturing. This study investigates design options for effective CO2 injection strategies to reduce liquid blockage and improve productivity in tight reservoirs.
We use dynamic compositional models to simulate condensate formation under realistic operating conditions. Initial sensitivity studies are performed using single well models, to design simulation cases that capture the condensate banking problem accurately for selected permeability scenarios. Then full field models are constructed to evaluate the potential of CO2 injection schemes: near-wellbore huff and puff, and field scale continuous injection. Different field development options are investigated, considering the effects of well placement, injected gas volumes, quality of injected gas and frequency of huff and puff cycles.
The results of this work show that CO2 huff and puff processes can be highly effective for mitigating condensate drop-out in tight reservoirs, whereas there is likely to be no significant advantage for huff and puff in comparison to continuous CO2 injection in moderately permeable reservoirs. Well spacing and injected volumes can impact recovery significantly: we suggest analytic methods, based on well drainage areas, to estimate suitable values for these parameters. As the production scheme will involve recycling CO2, we consider the effect of impurities in the injection stream: our study indicates that it is not essential to use pure CO2 but sensitivity studies should be performed to check the effects of injected gas composition on recovery. We also demonstrate that recovery from huff and puff operations can be improved by using variable-length cycles, and propose a method to adjust the injection periods dynamically.
In this paper, we have identified important parameters that can affect the performance of CO2 huff and puff processes in tight gas condensate fields. The methodology described here provides a guideline for simulation studies of CO2 injection, which will help reservoir engineers to optimize field development and operations.
Improved Characterization of Emulsions Associated with Inflow Control Devices
Authors: Jackson Mark , Hoskin Ben , Ling Nicholas , Johns Michael , Gudimetla Ravi , Conitsiotis Christian 
Published: November 2020

Abstract
Water-oil emulsion formation is commonly observed at wellhead chokes and topsides control valves, with the impact mitigated by chemical injection. The presence of emulsions downhole in Pyrenees wells was inferred from their significant production rate impact and confirmed by the uplift observed from downhole chemical injection. The Pyrenees fields are located in the Exmouth sub-basin offshore Western Australia. Through analogy between individual Inflow Control Device (ICD) orifice elements and wellhead chokes, ICDs were suspected as the source. This paper describes experimental confirmation of emulsion formation by orifice type inflow control devices in Pyrenees field horizontal well completions and proceeds to characterise the emulsions formed. A purpose built flow rig combined Pyrenees crude oil and produced water under low shear, simulating reservoir flow conditions, before flowing through an orifice element at rates equal to peak and mid-life production. With liquid flow rate held constant, water cut was increased in 10% steps from 0 to 100% water content. A key component of the experimental system is a benchtop Nuclear Magnetic Resonance spectrometer equipped for non-invasive Pulsed Field Gradient measurement of the Droplet Size Distribution of the emulsions formed. Droplet size distribution is a fundamental fluid property that significantly impacts emulsion rheology. The heavy end component of the crude oil was characterised by a novel Enhanced Saturate Aromatic Resin and Asphaltene analysis procedure to facilitate benchmarking of Pyrenees with emulsion formation tendencies of other producing assets. This quantitative demonstration of emulsion formation by orifice type ICDs at near reservoir conditions is novel, as is observation of partial emulsification, and represents initial steps towards generalisation of models for emulsion formation and their transport properties.
Combined Effects of Laminae Characteristics and Matrix-Fracture Equilibrium Hysteresis on Permeability Evolution of Fractured Sorbing Rocks
Authors: Zeng Jie , Liu Jishan , Li Wai , Leong Yee-Kwong , Elsworth Derek , Guo Jianchun 
Published: November 2020

Abstract
Permeability is a critical property of fractured sorbing rocks, such as shale and coal, as it controls the gas transport. However, two distinctive features are commonly not simultaneously included in existing permeability models. One is the stratified feature which has been evidenced by an appreciable number of laboratory investigations. The second one is matrix-fracture non-equilibrium induced matrix-fracture interactions during permeability measurement or field operations. The goal of this research is to uncover how the combined effects of the two features influence permeability evolution.
This study is extended from our previous research (Zeng et al. 2020a) based on the poroelasticity theory. The interbedding layers can be either perpendicular or parallel to the flow direction. Within each layer, the permeability evolution with multiple stages would occur due to the matrix-fracture non-equilibrium and effective stress variation. Therefore, the overall permeability behavior of layered rocks becomes more complex. To investigate the influence of laminae on shale and coal permeability evolution, an equivalent permeability model for multilayer rocks is established by means of weighted-average and weighted-harmonic-average methods. As for matrix-fracture equilibrium hysteresis, the pressure-dependent gas invaded volume ratio concept (Zeng et al. 2020a) is used to describe equilibrium-hysteresis-induced nonuniform matrix swelling.
The reliability of this model is checked by comparing with the published model which has been verified against three sets of gas injection experimental data collected from constant effective stress, constant confining pressure, and constant average pore pressure conditions. Our results indicate that the gas flow direction affects the permeability measurement significantly. If the gas flow direction is parallel to the layers, the overall permeability magnitude is close to that of the highest-permeability layer. However, the overall permeability evolution law can be different from that of the highest-permeability layer. When the gas flow is normal to the bedding, both the permeability evolution law and permeability magnitude are similar to those of the lowest-permeability layer.
A Network Data Analytics Approach to Assessing Reservoir Uncertainty and Identification of Characteristic Reservoir Models
Authors: Tan Eugene , Zafari Mohammad , Small Michael , Portes Leonardo 
Published: November 2020

Abstract
One of the challenges faced by companies in the oil and gas industry is the diﬃculty in assessing and quantifying subsurface uncertainties when planning for hydrocarbon exploitation. A commonly employed approach is to use available exploration and appraisal data to produce a range of possible subsurface realisations, through which hydrocarbon production forecasts are generated. Prediction of hydrocarbon production from these simulations are then used to assess the viability of a planned development concept and the associated subsurface uncertainties. However, due to the sparsity of field data and unpredictability of underground geology coupled with the typically large dataset sizes, the ability to rapidly quantify prediction uncertainty and provide an overview of the range of underground geologies leaves much to be desired.
Here we show that the application of a network science approach to oil production prediction data provides an intuitive way to visualize and assess reservoir uncertainty. A network transformation utilizing Pearson correlation and mean absolute error as similarity measures were applied to a dataset containing time series predictions of oil production for 10 wells simulated in 50 different subsurface realisations. Realisations were generated using a synthetic reservoir spanning 20 years of production. It was found that the network representation enabled the inference of reservoir uncertainty by simple visual inspection. Additionally, network measures such as the beta index were used with results supporting their viability in quantifying uncertainty. The application of clustering algorithms to the resulting networks was also shown to simplify the time series into component characteristic subsurface realisations.
We propose a method to quantify subsurface uncertainties and create a simplified representation of the characteristic modes associated with a range of subsurface realisations, greatly reducing the time required to conduct a cursory analysis. Our results demonstrate how the application of network science ideas may be applied to provide new ways of analyzing production data and performace predictions. These methods provide an opportunity to further refine descriptions of uncertainty by incorporating stochastic elements into the network as well.
Production Performance Analysis of the Biggest Underground Gas Storage in China
Authors: Song Lina , Xu Hongcheng , Wang Jieming , Zhao Kai , Liao Wei , Zhang Shijie , Zhang Gangxiong 
Published: November 2020

Abstract
HTB underground gas storage (UGS) is a gas storage facility rebuilt from a depleted gas reservoir. It is located in Changji Xinjiang Province, in northwestern China. With designed working gas volume 45×108m3 and peak working rate 27×106m3 per day, HTB UGS is the biggest UGS constructed in China. Since commissioning in June 2013, HTB UGS has been injecting gas 113.8×108m3, and withdrawing gas 78.2×108m3 until now. In order to analyze its production performance after 7 years operations, we figured out a systematic analysis method.
First of all, we built a production database for HTB UGS, collecting daily injection-production data, tubing pressure, and kinds of testing data of the storage. Also, we built a database for all 30 injection-production wells recording their geologic information, drilling information, gas injection-production information, etc. Based on detailed data, we analyzed the operating characteristics of the HTB UGS from 6 aspects: injection-production gas volume, liquid production volume, operating pressure, reservoir connectivity laterally and vertically, sealing of the trap and well-patten spacing.
It shows that 1) gas injection and production volume of the storage increases year by year, accounting for 20% working gas volume of UGS in China. 2) Oil and water production are relatively low. The gas is becoming more and more like dry gas. 3) The operating pressure during gas injection almost reaches maximum allowable storage pressure (34 MPa); while during gas withdrawal it reaches 26 MPa, far above the minimum storage pressure (18 MPa). 4) Overall reservoir connectivity is good in the lateral direction and it is disconnected in the vertical direction between E1-2z21 and E1-2z22. 5) The storage is well-sealed and there is no gas leakage. 6) The well-patten covers 80% of the gas storage. To sum up, HTB UGS works well generally from 2013 to 2020, playing an increasingly significant role in summer and winter seasons in China. However, in order to guarantee gas withdrawal in limited time (120 days in winter time in China), well pattern infilling is still needed in layer E1-2z22.
The construction of UGS in China started in 1999. At present, 27 gas storage facilities have been built and it is planned to build another 23 to generate more than 400×108m3 working gas volume by the end of 2030. However, a systematic performance analysis method for UGS has not been applied. This paper will offer the reference for production performance analysis of UGS.
A Campaign of 4D Seismic Monitor Surveys on Australia's Northwest Shelf
Authors: Thomas Peter , Harrowfield Gillian , Fitzpatrick Jeremy , Berglin Blair 
Published: November 2020

Abstract
We showcase an innovative campaigning and business-focused approach to reservoir monitoring of multiple fields using 4D (time-lapse) seismic. Benefits obtained in terms of cost, speed and the quality of insights gained are discussed, in comparison with a piecemeal approach. Challenges and lessons learned are described, with a view to this approach becoming more widely adopted and allowing 4D monitoring to be extended to smaller or more marginal fields.
An offshore seismic acquisition campaign was planned and successfully executed for a sequence of four 4D monitor surveys for fields located within 250 km of each other on the greater Northwest Shelf of Australia. The four monitors were acquired in H1 2020 comprising (in this order): Pluto Gas Field M2 (second monitor), Brunello Gas Field M1 (first monitor), Laverda Oil Field M1 and Cimatti Oil Field M1.
Cost savings expected from campaigning were realised, despite three cyclones during operations, with success largely attributed to detailed pre-survey planning. Also important were the choice of vessel and planning for operational flexibility. The baseline surveys were diverse and required careful planning to achieve repeatability between vintages over each field, and to optimise the acquisition sequence – minimising time required to reconfigure the streamer spreads between surveys. The Cimatti baseline survey was acquired using a dual-vessel operation; modelling, combined with now-standard steerable streamers, showed a single-vessel monitor survey was feasible. These optimisations provided cost savings incremental to the principal economy of sharing vessel mobilisation costs across the whole campaign.
Both processing and evaluation (ongoing at the time of writing) are essentially separate per field, but follow a consistent approach. Processing is carried out by more than one contractor to debottleneck this phase, with products, including intermediate quality control (QC) volumes, delivered as pre-stack depth migrations. While full evaluation of the monitor surveys to static and dynamic reservoir model updates will continue beyond 2020, key initial reservoir insights are expected to emerge within days of processing completion, with some even earlier from QC volumes. Furthermore, concurrent 4D evaluations are expected to result in fruitful exchanges of ideas and technologies between fields.
A Novel and Comprehensive Approach to Fix Conductor and Casing Hanger Leaks
Authors: Saharuddin Mohamad Kamil , Wan Zahari Wan Ezran , Md Fauzi Ahsraf Hidayat , Ahmad Khonif Hasrul Afendi 
Published: November 2020

Abstract
Gas leak at surface wellhead equipment can contribute to a major incident if not contain immediately. High intervention cost and long lead time for wellhead replacement then required operator to find fast fit for purposes solution to avoid extended loss of production time if well idle due to integrity issue.
The approach was to diagnose and quantify presence of the leak, leak communication path and leak severity by performing positive and negative test at all hanger seal port. Two method of gas imaging detection utilizing Optical Gas Imaging (OGI) and Thermal Imaging (TI) was tested to investigate the leak at gap between casing conductor and wellhead landing support ring. Preliminary study on wellhead completion schematic conclude to have two possible leak paths from 36" conductor annulus; through bottom seal 13 3/8" casing hanger or 13 3/8" annulus through casing hanger top seal. The rectification approach was to treat the leak inside out by injecting proprietary sealant into casing hanger seal to regain sealing capabilities. High performance fiberglass wraps plus metal repair putty applied as second barrier which usually use for pipeline integrity restoration.
Baseline diagnostic and post treatment data was compared to evaluate the treatment performance. Out of 12 casing hanger seal port, 9 port was treated with Pressure Activated Sealant (PAS) and 3 port was treated with Time Activated Sealant (TAS) passing the acceptance criteria well barrier envelope. Proper sealant selection was crucial to treat different leak characteristic and correct injection method was important based on sealant activation mechanism. Ultimately, both gap at conductor was encapsulated using wrap system sealed the leak from outside and passed the soapy test. Thermal imaging for gas detection was not as conclusive as optical gas imaging, however most importantly both of conductor observed to have no leak at the surface.
This paper outline sealant selection type and its activation mechanism used for conductor leak rectification field application. The various consideration during engineering study, diagnostic activities and rectification procedure were highlighted as well as the experiences and lesson learnt during the execution phase.
An Insight into Challenges Post Fiber-Optic Installation: A Case Study of Field B, Offshore Malaysia
Authors: Minggu Nur’ain , Kamarulzaman Ammar , Ting Chang Siong , Kamat Dahlila , Riyanto Latief , Ho Dylan Zhe , Zamdy Siti Nurdyana , P Mosar Nur Faizah , Kalidas Sanggeetha , Tan Chee Seong 
Published: November 2020

Abstract
Over the last few years, the oil and gas industry had observed a rapid increase in deployment of fiber optic sensing for downhole monitoring. In Field B, 7 wells have been permanently completed with Distributed Temperature Sensing (DTS) fibers that extend through the reservoirs section 2009 and 2015 respectively. After more than 40 years of production history, this was the first permanent installation of fiber-optic in SX Region. Undeniably the DTS provides a new surveillance experience for Field B; multiple conventional monitoring system can be replaced with permanent fiber monitoring while also effectively minimize production deferments.
This paper presents the real-life challenges of fiber optic applications in Field B, offshore Malaysia. DTS wells are located in satellite platforms which are not accessible on daily basis. While the focus is always on downhole monitoring deliverables, a large proportion of upfront deployment is to invest on the surface equipment that can be complex and costly for data acquisition continuity. As such, biggest challenges faced by Field B are essentially surface-related. Challenges encountered post DTS fiber installations in Field B includes digital oil field set-up, surface hardware replacement and maintenance, local electric room (LER) power-supply stability, data transfer protocol, continuous streaming of DTS data from offshore to onshore, reduced data resolutions, software and capability development. Over the life of the well, these challenges possess significant cost impact and most of time are not captured during the project planning and development stages.
In Field B, throughout 5 years post fiber-optics installation, multiple challenges have been overcome in order to maximize value of information from the downhole monitoring. Knowing that these challenges might impact the downhole monitoring deliverables, the plan for future permanent fiber optic installation in any asset should incorporate all the possible challenges with its mitigation plans identified and set in-place. The lesson-learnt highlighted are turned into future project best practices.
Temperature Effect on HP Gas Well Integrity: Thermal Wellhead Growth Challenges and Solutions
Authors: Almulhem Khalid , Mrsic Zoran , Thuwaibi Mohammed , Adesegha Rotimi 
Published: November 2020

Abstract
Determined efforts are being exerted to shore up the integrity of high-pressure high temperature (HPHT) gas wells, which includes studying all observed integrity failures and adjusting practices to prevent potential failures from reoccurring. In high-pressure high-temperature gas wells, casing thermal expansion is a challenge that should be considered in order to maintain the integrity of the well and surface equipment. The objective of the paper is to describe observed growth in a HP gas wells in relation to the wellhead temperature and how it behaves after cycling the well and how it can affect the annuli pressures.
As methodology, two elements varying during shutdowns were studied thoroughly to determine the extent of the impact they may have on the integrity of HP gas wells. These elements are pressure and temperature. While the linear increase of the wellhead growth with increasing temperature was apparent, the subsequent actions of shutting in the well to cool down and then reopening it led to further deterioration of the cement and the wellhead growth increased even further. The engineering solutions and stress analysis at surface facilities is designed to overcome the growth allowance.
The main observation looks at the temperature element and its effect on well integrity in that it analyses the temperature impact on the well’s tubulars and links it to the stresses caused to casing cement and the resulting wellhead growth. Study will also provide recommendations on maintaining well integrity and avoiding any further deterioration. The temperature impact was also observed in one of the wells after it was shut in and wellhead sensors were left to record shut-in wellhead pressure and temperature for about 14 hours. This gave a reasonable indication of how fast it takes for the wellhead to cool down to ambient conditions. In the subject well, the wellhead temperature dropped by 50% in about 2 hours.
As result of the study, in detail reasons for increased wellhead growth in HPHT gas wells and how to avoid it. It also gives recommendations on maintaining well integrity and reducing the impact of full contraction of the well’s tubulars during cooling; such as maintaining wells on constant production, minimizing open and shut-in cycling, and reducing the shut-in time duration.