bluuebunny/crossref_metadata_2025 huggingface dataset:
Quantifying Flow Behind the Liner during a DST using High Resolution Thermal Array Technology and a Novel Thermal Model
Authors: David Lavery , David Fyfe
Published: November 2020

In this case study, high resolution temperature array data, acquired during a Drill Stem Test (DST), were able to identify and quantify flow behind the liner. Quantifying the flow rate behind the liner between the production zones was of significant value to the operator to reduce the uncertainty in the Pressure Transient Analysis (PTA).

The high resolution temperature array was deployed clamped to the outside of the Tubing Conveyed Perforating (TCP) guns, which were used to selectively perforate multiple zones. Using wireless acoustic technology the temperature data were transmitted to surface to enable real time feedback during the DST. A novel thermal heat exchange model was built that could take advantage of the high resolution temperature array data acquired during the entire test. The results of the model were compared to the real data to validate the results and provide accurate flow rate measurements of the flow behind the liner in real time during the test. A sensitivity study on the various model input parameters was also carried out to reduce the uncertainty in the thermal model, the results of which are detailed within the paper. Being able to quantify the flow behind the liner allowed the operator to adjust their PTA results and provided a more robust reservoir model.

Typical thermal models in the industry are unable to quantify flow behind the liner in this environment. A new thermal model had to be developed that could take into account the complex heat transfer processes and take advantage of the high resolution thermal array data acquired during the DST. Despite the challenging wellbore environment during the test, the high resolution temperature data were used to provide a robust zonal flow confirmation and rate allocation during the flow periods.

Whilst Distributed Temperature Systems (DTS) are gaining popularity in the oil and gas industry, typically the current technology does not provide the high resolution required to be able to quantify flow behind the casing. This new model, when combined with high resolution thermal array data, has wide ranging applications not only during the DST but also in long term completions where monitoring well integrity is a real industry challenge.
Gas Rate Prediction in an Openhole Multi-Stage Fractured Well with a Revised Thermal Model
Authors: Sui Weibo , Zhang Di
Published: November 2020

The fiber-optic distributed temperatrue sensor (DTS) has been used for flow profiling in horizontal multi-stage fractured wells, and there were some reservoir/wellbore coupled thermal models presented by researchers. Although current theoretical models are developed for some certain application scenarios, the industry have realized the great potential of DTS for production prediction in unconventional resources. This paper presents a DTS flow profiling case for a horizontal multi-stage fractured well in tight gas reservoirs with open-hole packer completion scenarios by applying a newly improved theoretical model.

In this paper, we started with the conventional semi-analytical wellbore-fracture-reservoir coupled flow/thermal model which have been developed for cased, perforated, and multi-stage fractured wells, and revised it to consider the special feature of openhole packer completion scenario. Since the formation fluid firstly flows through the fracture into the open-hole annular space between formation and the packer liner, then flow along the annular space until meet the frac port on the production pipe, we add a simulation sub-region representing open-hole annular which helps to understand the flow and heat transfer inside it. The presented model successfully simulated the two-fold flow regime caused by the simultaneous flow and heat transmission in the annular space and the production pipe. In each stage, the DTS temperature data possibly show double drops due to Joule-Thompson cooling effects at the fracture and frac port locations if they are not consistent.

With the improved mathematical model, DTS monitoring data during a three-rate production test in a horizontal multi-stage fractured well in Erdos Basin of China was simulated and analyzed. The improved model with open-hole packer completion was applied and then the gas rate prediction was accomplished.
CO2 Storage with Enhanced Gas Recovery CS-EGR in Conventional and Unconventional Gas Reservoirs in Australia
Authors: Wang Hongcai , Rezaee Reza
Published: November 2020

Excessive greenhouse gas emission and natural gas shortage need to be tackled urgently nationally and globally. In this context, Carbon Capture Storage and Utilization (CCUS) has been proposed to: (1) mitigate the global warming by removing carbon from the atmosphere and, at the same time, (2) create value/reduce the cost by utilizing them for production. CO2 Storage with Enhanced Gas Recovery (CS-EGR) is well fit for the purpose of CCUS. This paper analyses the feasibility of CS-EGR in Australia by characterizing reservoir rock and fluid properties from both conventional and unconventional gas reservoirs, and by modelling the process of CO2 injection, gas production, and CO2 storage.

This paper discusses technical aspects of injection and storage of CO2 and the behaviours of CO2 and methane together with enhancement of gas production. Although both conventional and unconventional gas reservoirs are covered, the emphasis is given to the unconventional gas. CO2 is more preferentially adsorbed to shale or coal than CH4, so the injected CO2 will displace CH4 which then can be recovered. It is also miscible with natural gas and is good for re-pressurizing reservoir. However, these processes are highly influenced by many factors, such as reservoir temperature and pressure, total organic content (TOC), porosity, permeability, pore size (distribution), injection operation, mineralogy, fracture, fluids and so on. Numerical simulation is a perfect tool to study how different parameters interact with each other and eventually affect the efficiency of CS-EGR.

The authors undertake geological and petrophysical characterization of target formations in Australia. It is then followed by numerical modelling which takes consideration of reservoir characterization data and interaction between CO2, CH4, H2O and rock. The sensitivity analysis investigates the performance of CS-EGR at different scenarios and identifies the critical factors. It is worthwhile to mention that two gas injection methods, gas flooding, huff'n'puff, (or cyclic gas injection), are studied and compared.

Based on previous studies, this paper moves a step further by: (1) incorporating reservoir characterization data from Australia gas field in numerical modelling and exploring the feasibility of CO2 Storage with Enhanced Gas Recovery in Australia; (2) investigating both unconventional gas reservoirs and conventional reservoirs and makes a comparison between them; (3) comparing two injection methods for all different reservoirs; (4) performing sensitive analysis of multiple parameters identified from analysis and literature. CS-EGR is promising in achieving "net-zero emission" for Australia.
Drilling Performance and Risk Management Optimisation in Offshore Australia: Improving Overall Safety and Efficiency of Well Construction Process
Authors: Kirthi Singam Chandrasekhar , Hafezi Farshid , Rebello Clyde , Bartul Miroslav , Ali Anis , Naveed Muhammad
Published: November 2020

The emergence of Real-Time Well Construction Performance Monitoring Centers has significantly improved the service delivery for Operators across numerous offshore oil fields in Australia. New technologies and workflows were implemented for 3 Australian offshore wells, with the primary objective being to improve drilling efficiency while managing the associated risks. Additional objectives included optimizing daily operational performance, thus delivering time savings for the Operator and highlighting areas of possible improvements.

The workflows combined proven technologies, software and wellbore surveillance services, which delivered risk-free wells ahead of Authority for Expenditure (AFE), by targeting the reduction of nonproductive time (NPT) and invisible lost time (ILT), together with risk management.

The workflow began with a preliminary field analysis to identify the main challenges and areas that needed improvement. The key learnings were then consolidated on a comprehensive drilling road map by well section that outlined prevention and mitigation measures, expected rate of penetration (ROP) and recommended drilling parameters. The study also identified performance benchmarks such as average and on bottom ROP and connection time. Key performance indicators (KPI) were developed to monitor progress and track the well with respect to well improvements versus the benchmarks identified. The selection of the monitoring tools and modules required during the Execution Stage were developed based on the risks and KPIs identified during the field study and were further tailored to target specific challenges such as stuck pipe prevention, hole cleaning, shock and vibration and connection time.

The workflows enabled the flawless execution of 3 offshore wells 29.0 days ahead of AFE which saved the Operator USD 15.5M. The closed loop monitoring enabled real time interventions which aided in preventing risks such as stuck pipe, ensured efficient shoe-to-shoe drilling and avoided potential lost-in-hole (LIH) costs. This case study demonstrates the use of a novel approach to increase well construction efficiency by eliminating lost time while enhancing risk control. The main basis for success of this workflow was using existing and cost-effective technologies while capitalizing on the renewed synergy between different departments such as Drilling, Mudlogging and Well Operations analysis.

The workflow was and can be customized based on different needs, by combining specific modules for monitoring, analysis and wellbore surveillance services, to increase the efficiency of any well construction.
An Integrated Approach for Tackling and Resolving Horizontal Drilling Challenges in the Eromanga Basin to Maximise Production Benefits
Authors: McDermott Samuel , Wang Haifeng , Liu Yang , Jiang Xiaohu
Published: November 2020

Eromanga Basin in central Australia was deposited from early Jurassic to late Cretaceous and has witnessed commercial discoveries in different formation units throughout the basin's spatial distribution. Lately, operators have shifted from vertical to horizontal wells to enhance production outcomes. However, there are still many challenges for achieving and enhancing these benefits with horizontal drilling. These include navigating an undulating reservoir structure whilst staying in the target zone and maintaining appropriate vertical standoff from oil water contact (OWC) to avoid early water breakthrough.

In this paper, the author summarizes the experiences and approaches made in tackling and resolving these challenges, by elaborating on the new methods applied during the recent horizontal drilling campaign. These include new drilling technologies, such as the latest rotary steerable systems and new logging-while-drilling technologies, such as the multilayer bed boundary detection services. The methodology of using this data both while-drilling and post-drilling for critical decision making on both geosteering and completion strategies, is also addressed. The author illustrates an integrated approach that was adopted by incorporating new data into the reservoir model for the purpose of referencing and planning future wells.

Case studies from two of the recent wells are discussed in detail to illustrate the operational workflows and the integrated approach. Landing and geosteering practices are examined separately to demonstrate how to achieve best results and avoid both identified and potential pitfalls. The overall drilling and production performance of the recent ten wells are summarized, as are the results of applying these methods. Finally, the author reveals the new insights that the post-job data integration brought for the field.

This new approach has allowed the operator to drill an increased number of wells than originally planned in the same timeframe. This approach has also allowed for longer wells to be drilled. By comparing the production benefits with the cost of drilling, the author shows the viability of these methods in resolving the challenges of horizontal drilling in this region.
Well Inflow Performance Under Fines Migration: Analytical Model, Production Data Treatment
Authors: Loi Grace Ming , Chequer Larissa , Nguyen Cuong Cao , Zeinijahromi Abbas , Bedrikovetsky Pavel
Published: November 2020

Fines migration causes significant formation damage during oil and gas production. The reliable prediction of well performance and extend of the damaged zone allow for planning and design of well stimulation for prevention, mitigation and removal of the damage. We derive a novel analytical model for production well performance during fines migration. The model includes explicit formulae for concentrations of suspended and strained fines, and the expressions for skin factor and well impedance. Ten field cases exhibit close match with the analytical model. Moreover, the tuned parameters belong to common intervals of their variation. The work provides means for reliable well behaviour prediction based on production history and coreflood data.
Probabilistic Assessment of Pressure Depletion and Inflation and its Impact on the Drilling Sequence for the Sangomar Field, Senega
Authors: Gavin Lisa , Jagtenberg Pieter
Published: November 2020

The Sangomar Field Development – Phase1, located offshore Senegal, will consist of 23 wells targeting stacked reservoirs, with horizontal lengths up to 1,500m. Due to the long drilling campaign, wells are likely to be drilled after first production, targeted for 2023. At the time of drilling, reservoir pressure in these wells will be affected by nearby producers and injectors, which will reduce the mud window in the boreholes, affecting the drillability.

Vulnerable wells are identified by a deterministic borehole stability assessment based on mud weight windows and a probabilistic well-by-well analysis of reservoir pressure at the time of drilling. The estimated mud weight windows are unique to each well and a function of completion type, overburden thickness and well azimuth. Capturing reservoir uncertainties within the uncertainty framework results in 216 models which are reduced to a more manageable 20 models for simulation using a distance-based K-medoid algorithm. Maps of maximum depletion and inflation are generated for each of the medoids.

With this work, the importance of probabilistically assessing reservoir pressures is demonstrated in the context of developing a robust drilling sequence, highlighting that results can vary significantly depending on the reservoir models used. Potential magnitudes of depletion and inflation in some scenarios are significantly greater than initially anticipated. The combination of borehole stability assessment and probabilistic well-by-well analysis of reservoir pressure allows clear identification of wells at increased risk of borehole stability problems caused by injection or depletion. Subsequently, the drilling sequence is updated to mitigate borehole stability risks by executing potential problem wells prior to first production and prioritising key water injectors, enabling management of post-production depletion while continuing to meet the other objectives such as maximising early production potential.

This paper outlines an innovative workflow which captures the range of subsurface uncertainties to define probabilistic impact of depletion and injection on borehole stability. Within the literature we have not seen any examples of depletion and inflation being assessed probabilistically on multiple models or using a map-based format. Depletion and inflation are also often discussed in the context of producing fields, not during the first phase of drilling, as is the case for the Sangomar Field.
CO2 Injection for Improved Recovery in Tight Gas Condensate Reservoirs
Authors: El Morsy Mahmoud , Ali Samad , Giddins Marie Ann , Fitch Peter
Published: November 2020

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

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

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

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

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

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

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

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

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.
Fiber Optic Distributed Temperature Sensing as an Alternative Interpreted Intelligent Completions.
Authors: Minggu Nur'ain , Kamarulzaman Ammar , Riyanto Latief , Ting Chang Siong , Kamat Dahlila , Ho Dylan Zhe , Zamdy Siti Nurdyana , P. Mosar Nur Faizah , Kalidas Sanggeetha , Tan Chee Seong
Published: November 2020

This study aims to validate and track valve positions for all the zones applying recorded distributed temperature sensing (DTS) data interpretation to propose the best combination of downhole inflow control valve (ICV) openings to optimize Well X-2 multizone commingled production. Fiber DTS is relied on as an innovation against downhole conditions that has compromised the three out of four downhole dual-gauges and valve position sensors.

For zonal water control purpose, ICV cycling and positioning have been attempted in 2019. The valve position tracking derived from the compromised downhole dual gauges and valve position sensors does not tally with the surface flow indication overall. Consequently, the original measurement intention of the fiber DTS as back-up zonal-rate calculation profiling and as potential sub-layer flow-contribution indicators is brought in as contingency zonal valve-opening tracking and guide that proved valuable for subsequent production optimization.

Downloaded DTS data is depth matched and validated against known operating conditions like time of each cycling stage and surface well test parameters (i.e. Liquid Rate, Watercut, Tubing Head Pressure (THP), Total Gas, Gas-Oil Ratio (GOR)), etc. To establish a baseline, several DTS traces of historical operating condition during a known stable period were selected, i.e. stable flowing condition at only Zone 4stable shut-in condition at surface with only ICV Zone 4 is opened

Downhole valve-position tracking can be interpreted alternatively from induced fiber temperature activities across the valve depth with a good temperature baseline benchmarking from DTS temperature profiling. In one of these alternative interpretations based on fiber temperature, it is found and validated that Zone 1 ICV is Closed, Zone 2, 3 and 4 are in opened position and continuously producing at any cycles. This is in conflict of zonal production control understanding initially based on the compromised downhole sensor indicating that all the zonal valves are supposedly in fully closed position.

In this case-study, DTS data has been proven useful and as an innovative alternative to determine downhole valve opening with analogue to flow contribution derivation methodology. Therefore, anytime in the future where Well X-2 valves cycling is planned to be carried out, there is a corresponding operating procedure that needs to incorporate onsite real-time DTS data monitoring to validate tracked valves positioning.
Installation of Annulus Cement Plugs Using Perforation, Wash and Cement Technique, a Lookback from a First for Australia
Authors: Bothamley Ryan , Haigh Mike , Soudi Mehdi
Published: November 2020

The Gorgon Foundation Project (GFP) development comprises of the Gorgon and Jansz-Io gas fields located in offshore Western Australia. To maintain gas supply, the Gorgon Stage 2 (GS2) project will expand the existing infrastructure with additional subsea production wells. The Gorgon Stage 2 (GS2) well architecture is designed to deliver a 7 5/8 in. tubing × 7 in. production liner Cased Hole Orientated Perforation completion (CHOP).

An unsuccessful production liner primary cement job resulted in an area of uncemented wellbore -casing annulus and a sand containing mobile water exposed. This led to the unresolvable uncertainty of water crossflow into adjacent produced sands. Under the current flow assurance restrictions, the risk of produced water could reduce production rates or require the well to be shut-in. To mitigate water flow potential, cement plug annulus impediments (baffles) were installed. The objective of these plugs are for reservoir management, not abandonment barrier plugs. This allowed an optimized scope for verification and contingency operations planned and executed.

This paper provides an insight into the collaborative efforts made by the Subsurface, Drilling and Completions (Wells) teams and Service Partners to plan and successfully execute two (2) Perforate, Wash and Cement plug jobs. Operations include the use of Tubing Conveyed Perforations (TCP) and Closed Loop Cup Type Wash and Cement tool, a first for Chevron in Australia. The cement plugs were deployed from a semi-submersible in ~220 m of water and placed at depths of ~5,700 mMD and ~5,500 mMD respectively, at inclinations of 60° and in high static bottom hole temperatures up to ~157°C.

The key challenges and lesson are discussed including planning to optimize swab cup integrity in high temperature operations.
Application of Computational Fluid Dynamics for Parametric Optimization of Jet-Type P/W/C Technique
Authors: Phadke Amal , Hovda Lars , Gonuguntla Praveen , Mueller Dan
Published: November 2020

Perforate-Wash-Cement (P/W/C) is a well plugging technique extensively used by ConocoPhillips in the Greater Ekofisk Area over the last ten years. In Jet-type P/W/C, Tubing Conveyed Perforating (TCP) guns perforate casing in the target interval before the zone is washed and a cross-sectional cement plug is installed using a specialized Bottom Hole Assembly (BHA). The goal is to maximize the cement plug quality through optimizing the BHA and operational process parameters within constraints imposed by the operating conditions. This paper describes application of Computational Fluid Dynamics (CFD) to achieve this objective. CFD is well suited for modeling wash and cement processes including the associated non-Newtonian fluids. A CFD model of these processes employs unsteady multiphase Reynolds Averaged Navier Stokes (RANS) based Volume of Fluid (VOF) approach with a Shear Stress Transport (SST) K-omega turbulence model. BHA translation and rotation are simulated using moving deforming-layering mesh with interface approach. Physical properties of non-Newtonian fluids selected are based on in-situ conditions and derived via lab tests. CFD-specific considerations such as domain size, turbulence model, mesh type and size, and computational timestep are discussed in this paper. The magnitude and duration of the jet-induced "pressure pulse" in the annular space between the formation wall and the casing are a key to efficient displacement during the wash and cementing processes. Displacement efficiency, in terms of the percentage of mud or cement in a control volume as a function of time, depends on perforation size and density, nozzle size/number, flow rate, fluid properties, as the ROP/BHA pulling speed and tool RPM. Key findings from a parametric study to optimize these parameters are presented. To validate CFD nozzle flow predictions and to rule out potential for false results due to cavitation, laboratory tests were performed under pressurized conditions. A comparison of results from CFD simulations using traditional versus optimized parameters are presented, demonstrating significant efficiency improvement achieved. The study initially focused on North Sea application. Encouraged by substantial improvement in process efficiency through parametric optimization, the technique was extended to UK operations and is planned for the Bayu-Undan field. Cementing simulation results for Bayu-Undan specific well configurations are presented, showing how CFD modeling helped reveal less than ideal cementing efficiency. Ultimately, this work provides significant time savings and quality improvement for P&A projects while maintaining a high safety standard.