bluuebunny/crossref_metadata_2025 huggingface dataset:
Towards the Development of Chemical Selection Criteria for Subsea Preservation, a Practical Example
Authors: Shepherd A. G. , Hoban P. , Venugopal S. , Bos T. , Lorimer S. , Shade R. , Jensen N. , Backus F. , Luderer M.
Published: October 2016

Industry best practices dictate minimum fluid requirements for preservation of subsea equipment. The choice of chemical package to be used in such operations may be guided by a number of criteria, such as: carrier fluid composition and quality, exposure temperatures, pressures, preservation time, metallurgy, risk of microbial induced corrosion, predicted marine growth, expected concentrations of oxygen and or other contaminants (to name a few). Rules of thumb and regulatory/HSSE/regional considerations play an important role in chemical selection. More often than not, there is no off the shelf/one size fits all solution, particularly for deepwater and or remote locations. Thus selection criteria and performance indicators need to be clearly defined, verified and assured under laboratory conditions, before deployment. A well selected formulation is an enabler in ensuring readiness of a fit for purpose package in the operational environment.

In this work we present an example of the steps required for a structured approach to chemical selection for preservation. The selection involved looking at various MEG/water ratios proposed as carrier fluids. In addition, specific additives were considered for a defined set of conditions (e.g. temperature, oxygen content, metallurgy). The work focused on traditional chemistries used widely in preservation and novel applications. Some of the chemistries described here have not been reported previously for either water-based and or MEG/water based preservation, to our knowledge.

The results from this work show that there are differences in behavior for traditional chemistries employed for water based preservation formulations compared with MEG/water based options. However, it is possible to have an optimum formulation for a MEG/water based preservation fluid to meet KPIs if a structured approach is followed.
Industry Collaboration on Technology Development in WA
Authors: Kavanagh Neil , Otto Claus , Korsen Peter
Published: October 2016

During 2015, it became apparent oil prices were going to remain ‘lower for longer’ and budgets would be adjusted accordingly. As such technology development would be reduced and slowed down. As a result Western Australian oil and gas operators Woodside, Shell and Chevron are considering if and how increased collaboration in technology and innovation can support each individual company and the industry as a whole, by joining efforts and therefore leveraging investments and sharing lessons learned and best practices.
Modelling Carbon Storage Prospectivity in the Southern Margin of the Offshore Gippsland Basin, Australia
Authors: Ricard Ludovic P. , Michael Karsten , Dance Tess
Published: October 2016

A collaborative study has recently completed a storage capacity prospectivity assessment and pre-competitive data acquisition program in the southern margin of the offshore Gippsland Basin, Australia. Potential CO2 storage sites that could become available in the next ~25 years will be restricted to sites in the nearshore and southern parts of the offshore Gippsland Basin. This is in order to minimize possible resource interactions with ongoing petroleum production and low salinity groundwater in the northern and central parts of the basin. The injection target, the Latrobe Group has been identified as a suitable candidate for large-scale CO2 geological storage.

As part of the storage capacity assessment, a detailed geological model of the Latrobe Group sequence was constructed in an area of the southern margin of the basin. The model evaluates two main east-west-trending fault systems separating the model into three structural segments: a deep depocentre, flanked by the Southern Terrace, and thin Southern Platform. The sedimentary sequences comprise coastal plain to shallow marine sandstone deposits interbedded with laterally continuous coals and mudstones, which act as seals and baffles of varying quality. Uncertainty in the reservoir architecture and the impact on connectivity of the permeability field was assessed by way of multiple model realizations. The model was then used as the basis for a series of capacity and injectivity estimations employing theoretical, analytical, and numerical flow simulation modelling techniques.

At the highest end, for an area excluding the platform and assuming low sweep efficiency, estimates of the theoretical CO2 storage capacity ranged between 865 million tons (Mt) and 2,800 Mt. For the analytical model estimates were up to 900 Mt and numerical methods estimates were in the order of 200 Mt to 550 Mt assuming 3 injection wells in a 40 × 40 km area over 30 years. All of the results are highly sensitive to the estimation method used and input provided such as, net area defined, injection interval selected, uncertainties on fault seal, and boundary conditions. However, the insights gained from the numerical modelling studies in the region have indicated that carbon storage injection has the greatest potential south-west of the Bream field. After 1,000 years post injection, accumulations of mobile gas can be observed at different locations within the model, suggesting several vertical and lateral pathways. Key outcomes of the simulations support the concept of the southern margin of the Gippsland Basin being prospective for further CO2 storage exploration, namely that it is feasible to achieve injection and containment of commercial scale volumes of CO2 in parts of this region without adversely impacting existing resources.
Zonal Water Injection for a Nine-Layer Reservoir-A Case Study
Authors: Fuchao Sun , Zhenkun Zhu , Yulin Yang , Mingxin Zhao , Yang Gao , Jiaqing Yu , Tao Zhang
Published: October 2016

80% reservoirs were developed by waterflooding in China. The average layer number lies between three and four. As old oilfields reached high water-cut period, the reservoir needs further subdivision, usually more than seven layers. Conventional zonal water injection technique cannot meet the need of more than seven-layer subdivision because of small distance between regulators, thin interlayer, big releasing force of tubing and low efficiency in zonal flowrate adjustment. To solve this problem, we developed a step-by-step type packer which was released by lifting. The release force has nothing to do with layer number. All the packers were designed to release one by one. The maximum force was 30t. For small distance of regulators, we used two types of eccentric bridges together called positive oriented type and negative oriented type. By this way, the smallest distance was less than 0.7m. Double tubing packer was applied to realize effective seal for thin interlayer and it could overcome tubing creep which made it successful seal within 0.5m. This technique has applied more than 1147 wells in Daqing. The minimum distance between regulators is 0.7m. The minimum interlayer is 0.5m and the maximum layer number was 10. The technique process is normal during whole operation including packer set, open every choke completely, packer seal status on-line test and on-line flowrate adjustment. Through zonal water injection for those more than 7 layers, we conclude that the ratio of water absorption has increased by 8.1%. And the corresponding production thickness increased by 7.5%. The production of surrounding well increased 0.43t and the water cut decreased by 0.56%. The average zonal test and flowrate adjustment time is within 3.98d. All in all, it is an effective way for further waterflooding oilfield. Conventional zonal water injection technique cannot meet the need of more than seven-layer subdivision because of small distance between regulators, thin interlayer, big releasing force of tubing and low efficiency in zonal flowrate adjustment. The technique this paper introduced can solve this problem and it is widely used in Daqing. The results showed its adaptability.
Application of Permanent Integrated Water Regulator in Offshore Oilfields
Authors: Deli Jia , He Liu , Fuchao Sun , Xiaohan Pei , Wei Sun , Shujin Zhang , Chongjiang Liu , Mingxin Zhao
Published: October 2016

In the Bohai Oilfield in China, the water injectors with sand control completion are characterized by multiple layers (2-6 layers), high single-layer injection rate (300-700 m3/d) and large borehole deviation (30-60°). The conventional wire fishing and the high-efficiency measuring and adjusting based separate layer water injection can not satisfy completely the production requirements of separate layer injection at offshore platforms. In order to solve this problem, a type of implanted integrated water regulator based separate layer water injection technology was designed and developed. The integrated water regulator is implanted with the tubing at the downhole injection interval. It is integrated with the functions of the injection rate and pressure monitoring in each interval and the opening monitoring and adjustment of regulating valve. A special type of three-way ceramic plug was developed for high injection rate, and the anti spitting valve was adopted. Enhanced steel cable was used for power supply and communication with the ground main frame. The ground main frame (explosion proof ExdII BT6) was set at the offshore platform for multi-well dragging control. A set of ground main frame can perform time-sharing monitoring and controlling on 8 intervals in 7 water injectors, so it can satisfy the requirements of most water injectors in Bohai Oilfield. Pilot test verifies that this technology reaches the design requirements and guarantees the qualification rate of water injection in each interval. Its technical monitoring data can be used for oil reservoir analysis to improve water flooding results.
Demystifying Log Quality Control
Authors: Storey M. C.
Published: October 2016

All would agree that bad data should not be let into the organization’s systems and its decision-making processes, yet there are no industry standard methods on how best to assure this for well log data. Electric well logs are the principal data sets for all geotechnical personnel in this industry: logs generally constitute the main continuous and relatively high-resolution records describing a wellbore, and they are available over the main depth intervals of most wells drilled for hydrocarbon exploration and production.

The specialized contractor companies that acquire the logs have quality management systems in place to ensure compliance and consistency with their own specifications. The data deliverables are therefore subject to some quality control before delivery to the operating companies, although it is of a general nature and focused on the acquired data, rather than on their future exploitation.

On delivery, the responsibility for any post-acquisition quality control of the well logs frequently falls on inadequately trained and supervised geotechnical persons, who may skim over it on account of its being "too hard" or "too urgent". People responsible for log quality control frequently report that they find it "difficult" or "overwhelming" and that they "don’t know where to start". Subject matter experts themselves know that logs must always be checked and perhaps conditioned before they can be used. Yet few of them have simultaneously the knowledge, the experience, the reference information, the tools and the time to verify the fitness-for-purpose of the data methodically and confidently. This systematic requirement is costly for organizations, and its uncertainty exposes them to unnecessary risks. The situation is exacerbated by concurrent increases in the variety, volume and complexity of the log data and in their rates of change.

There must be a better way to assure log data quality and readiness for exploitation. The objective of this paper is to propose a framework to formalize and simplify log quality control in operating companies and other data-user organizations.
Gravity Driven Fingering and Mixing During CO2 Sequestration
Authors: Ajibola Jeuspelumi , Adam Alexander , Muggeridge Ann
Published: October 2016

Injection of carbon dioxide into deep saline aquifers is one way to reduce greenhouse gas emissions. Carbon dioxide, usually a super critical fluid at aquifer pressure and temperature conditions, is lighter than the resident brine and so forms a gas cap above the water. However, over time it dissolves in the water, creating a density inversion which induces gravitational instability. Understanding whether the dominant mixing mechanism is convective mixing rather than pure diffusion is important as this controls the timescale over which the carbon dioxide-saturated brine mixes with the unsaturated brine. This paper presents numerical simulations, using a finite difference reservoir simulator, to evaluate the predictions of analytical solutions for stability analysis and growth rate of the fingers of different wavenumbers at different Rayleigh numbers (Ra). The effects of density difference, permeability anisotropy and diffusion (both longitudinal and transverse) on fingering behaviour were investigated through the dimensionless Rayleigh number. The density difference and the vertical permeability were found to mainly control the degree of instability. At Rayleigh numbers greater than 800, fingers are present and the degree of fingering increases with Rayleigh number. Growth rate analysis showed that growth rate is directly proportional to Rayleigh number and time. The critical time (at which flow becomes unstable) varies inversely with the Rayleigh number whilst the corresponding critical wavenumber number varies linearly with the Rayleigh number. These results are consistent with previously reported linear stability analyses providing a validation of the simulator. Numerical simulation results were also validated against experiments. These validations both show that the simulator is robust and can thus be used to investigate more complex situations (heterogeneity) that cannot be analysed mathematically.
Investigation of Shale Gas Numerical Simulation with Fracture Stress-Sensitive Using Discrete Fracture Network Model
Authors: Mi Lidong , Jiang Hanqiao , Tang Ligen , Li Junjian , Killough John E.
Published: October 2016

The exploitation of unconventional reservoirs is increasingly a major source of long-term energy in the word. Research results have revealed that the natural fractures occur in shale gas reservoirs and many shale outcrops, cores, and image logs contain fractures or fracture traces, and microseismic event patterns associated with the hydraulic fracture stimulation have been ascribed to the natural fractures reactivation. Hydraulic fracture treatments also induce complex fracture geometries in naturally fractured shale gas reservoirs.

The production performance of shale gas plays denpend strongly on the existence of a dense and conductive network volume of the well. Most of shale gas reservoirs exhibit a higher degree of heterogeneity and complexity created by both natural and hydraulic fractures, whose permeability is stress-dependent. In order to describe the fracturs's seepage characterization explicity, the discrete fracture network (DFN) model is adopted in this research when the conventional continuum model cannot meet the requirements of the fractured shale gas reservoirs numerical simulation. The nonlinear partial differential equations about the seepage flow mathematic model are solved by finite volume method using the C-sharp programming language. The fracture permeability stress-dependent experiments have been conducted on shale core samples, and then the fracture aperture-pressure correlation is combined with the mathematic model of DFN to demonstrate the fracture conductivity potential impact as pressure drops during production.

The lab experiment results show that the fracture aperture is strong stress-sensitive at low pressure (0~20MPa). The model is used to do a simulation on a random generated fractures network, which is used to represent the fractured shale gas reservoir, to study the effect of the stress-sensitive on the flow and transport characteristics in the fractured porous media. Results show that: the fracture permeability stress-sensitive has a significant impact on the production and should not be ignored.
Practices of the Integrated Management System for Injection Water in Brown Field –Case Study
Authors: He Liu , Shujun BAO , Zixiu Yao , Fuchao Sun , Jiaqing Yu , Deli Jia , Yang Gao
Published: October 2016

As the exploration degree and strength are continuously increased, both average water cut and natural decline rate have the tendency for increase. Hence various problems and contradictions are exposed, it's increasingly difficult to offset the influence of production decline and water cut increase on petroleum production, which severely impacts reservoir development efficiency and economic benefit. Prominent contradictions are as follows. 1) After an oilfield enters into a high water cut stage, the conflict between injection and production is very serious, such as unequal water-flooding producing reserves, high injection pressure of some water-injecting wells, low productivity of partial oil wells because of blocking created by mechanical impurities, and poor layering water-injection technique. 2) Affected by reservoir heterogeneity and water injection, Injection profile is non-uniform in longitudinal direction, water-flooding hierarchy and degree of reserve recovery of high permeability layer is relatively high as a result. The water flooding development effect of high water cut oil field is in urgent need of improvement. 3) Influenced by reservoir's poor connectivity and injection water quality, the injection pressure is high for some injection wells, resulting to a decline of injected water volume, which couldn't meet the demand of injection allocation. To solve the above problems, it is necessary to build an integrated management system for injection, which could both cover the underground and above-ground. In the meantime, technical efficiencies should also be improved. Injection-production network is further perfected, which aids to solve the problem of lack of water injection well spots and unbalance of injection and production; Based on hydrodynamic principle, kinds of injection allocation regimes are implemented; Injection of under-injected wells is enhanced, which increases the water-drive swept volume; Tests of layering distributional injection and profile control are also conducted using various methods; Finally, quality analysis & investigation and compatibility research of injected water are completed, reasonable treatment is done according to the compatibility, which improve the quality of injected water.
Innovative Experimental Design Workflows for Coupled Models
Authors: Swarbrick Thomas , Muller Mathieu
Published: October 2016

The Wheatstone and Iago gas fields, located approximately 110 km northwest of Barrow Island in the Carnarvon Basin, are developed through a common subsea and offshore platform infrastructure. The production forecasts for the Wheatstone Project are generated using reservoir simulation models for both fields coupled to a shared production network model. This ensures the appropriate representation of boundary conditions on the production system, such as well back-pressures. Typical forecasting workflows in a greenfield environment include running experimental design (design of experiments) to generate probabilistic forecasts of field responses. However, conventional experimental design workflows are based on simulations of a single field and are often completed without coupling the reservoir model to a production network model.

This paper will discuss the improvements to conventional simulation workflows made by the Wheatstone Reservoir Engineering Team. These refinements, which enabled running experimental design with both reservoir models coupled to a production network model, allowed responses to be generated and reviewed at the project level. This approach accounted for field interference through the production network and afforded the opportunity to understand the production interactions and relationships more accurately and thereby establish a vantage point for improved optimisation. The improvements were necessary to overcome some of the commercial and in-house software limitations constraining the workflow and results.

This type of simulation workflow had not been achieved to this extent previously within Chevron Corporation. The approach described here allowed the direct generation of project level responses, such as timing of future drilling campaigns, which would not have been practical or reliable otherwise. Future improvements of this modelling workflow will consist of standardising the workflow within the Corporation, using it for history matching later in life as well as decreasing cycle time on more routine simulation work.
Predictions of Relative Permeability for Low Permeability Reservoirs and its Scale Effect
Authors: Lei Zhengdong , Liu Tong , Xie Chiyu , Wang Moran , Zhang Zike
Published: October 2016

Nowadays, reservoirs with a low or extremely low permeability are of crucial importance for additional oil/gas recovery. Better understandings of multiphase displacement at pore scale in such unconventional reservoirs are necessary. Since the microscale interfacial transport plays a very important role in such processes, researchers were devoted to discover phenomenon at smaller and smaller resolution, and even further to nanoscale. However, this is extremely consuming on both experimental techniques and computation resources. Therefore, we are wondering whether there exists a cut-off resolution or not, below which the absolute and relative permeability are changeless.

In this study, the Navier-Stokes equation for fluid flow is directly solved through porous media. For two-phase flow, the volume-of-fluid method is applied. The numerical code is written within the framework of OpenFOAM, which is a widely used open source CFD solver recently.

The method is validated through several testing cases, which indicates the accuracy of capturing the interface action, wetting phenomenon, and permeability. After validations, we perform a series of modeling of single-phase and two-phase flow simulations in low permeability reservoirs, with special focus on the scale effect. The rock samples are taken from the low-permeability Changqing oil field in China. We reproduce the digital rock structures at various scales by using the micro-CT scanned data. The results indicate that the scanning scale has great impact on the predicted permeability, and the reservoir permeability increases with resolution due to the increasing of micro pore connectivity. However, this tendency is found to decline when reaching a higher resolution.
Case Study of Blocking Water Coning in Horizontal Well for Steam Stimulation in Heavy Oil Reservoir
Authors: Yu H. , Li L. , Zheng J. , Fu X. , Ji W. , Gao W. , Liu H. , Liu Y. , Yan F. , Luo C. , Liu J. , Zhang P. , Li T. , Han X.
Published: October 2016

Water coning is one of the factors restricting the oil development of steam stimulation horizontal wells in highly porous and permeable sandstone reservoirs with bottom water. In order to control water coning and enhance oil recovery, an effective blocking method is described in detail in this paper.

The core of the technology is accurate water exploration with temperature profile and multi slug blocking system. Based on temperature profile and permeability distribution between the target A and B, the water coning is the low temperature section. The multi slug blocking system is comprised of the pre-slug nitrogen, the middle slug conventional gel and the near wellbore blocking slug-the original high temperature resistant plugging agent. The main function of pre slug nitrogen is pushed away bottom water from the near wellbore area. The middle slug conventional gel consists of HPAM and organic cross-linking agent with strong sealing capacity and the applicable temperature under 90°C. It has two functions, one is blocking the temperature lower than 90°C formation, on the other hand is to prevent the backflow of nitrogen. The near wellbore blocking slug is a new low cost and high temperature resistant agent system. The new low cost and high temperature resistant agent system is a solution system without solid particles, which is based on inorganic materials, organic materials as the inducing agent and surfactant as the stabilizer. The viscosity is about 3mPa·s at room temperature. The system began to solidify at 80°C and form the whole solid state finally. The new low cost and high temperature resistant agent system can be able to bear 350°C, and the residual resistance coefficient is as high as 30. The design of slugs is based on the temperature distribution of reservoir.

Since the beginning of 2010, the experimental well has experienced 6 cycles of production, oil production 5300t, cumulative water production 41800t, composite water cut 88.7%. Before water plugging, the cycle oil production is 246t and composite water cut is 96.5% in the 6 cycle. After water plugging, the daily oil production reaches up to 10t from 0.2t and the daily water cut reduces to 50.3% from 99%. The cycle oil production is 1722.7t and composite water cut reduces to 59.7% in the 7 cycle, and the input-output ratio increases to 1:5.

The plugging method can effectively restrain the coning of bottom water and realize reducing water cut and enhancing oil production. It has a very important significance to the development of heavy oil reservoir with bottom water.
Gorgon LNG - Optimising Gas Supply
Authors: Walters Mark
Published: October 2016

The Gorgon project represents a tremendous vote of confidence in the hydrocarbon potential of the Carnarvon Basin, with foundation field resources underpinning a lifecycle of future gas supply projects developing the wider deepwater resource base. With the foundation development costs mostly sunk and production ramping up, investment exposure is at its lifecycle peak and there is intense focus on safe and reliable operations.

However, there is also a need to continue to mature upstream gas supply opportunities. Projects to continue developing the foundation fields are already moving through the planning and development process. Looking beyond those, activities are in progress for selecting the first wave of future gas supply projects and beginning their first steps of development planning.

Distant, deepwater developments carry multiple risks with complex geology, costly and therefore limited data acquisition and record-breaking flow assurance requirements. Long development schedules result in limited ability to respond to uncertainty in foundation subsurface outcomes. Opportunities to maximise lifecycle value include standardisation of "subsea building blocks" and careful planning of new infrastructure to capture geographical and execution synergies.

Chevron and its joint venture participants have invested in an extensive deepwater exploration and appraisal program and are well-positioned to plan for the future. Building a gas supply plan involves a complex combination of portfolio and project principles and processes, drawing upon multiple disciplines and functions in the value chain including exploration and appraisal, early concept project planning, major capital project execution and base business operations.

At this early stage in the Gorgon lifecycle, a pragmatic approach has been taken to deliver effective portfolio planning, providing both the long term view and driving the near term selection decisions for the next wave of supply projects. This paper describes some of the insights and trade-offs being learned and applied in developing the gas supply plan.
Use of Hollow Glass Spheres in Lightweight Cements - Selection Criteria
Authors: Mata Clara , Calubayan Amor
Published: October 2016

Cementing across highly depleted zones and weaker formations requires low density cement systems capable of reducing the hydrostatic pressure of the fluid column during cement placement. If wellbores encounter weak or depleted zones, standard cement cannot be used because the bottom-hole pressure will exceed the pressure gradient and cement will be lost to the formation. Service companies offer cement solutions made light enough to circulate in such situations while retaining the ability to withstand down-hole conditions and maintaining adequate compressive strength to meet regulatory guidelines. Lightweight cements can be achieved using water extension, foamed cement or lightweight microspheres. This paper focuses on the use of lightweight microspheres as density reducing agents. Preliminary experimental data comparing different grades of hollow microspheres is discussed. Cement slurries containing hollow glass spheres and other lightweight hollow microspheres were evaluated while still liquid and after cured. While still liquid the cement slurries were characterized in terms of effective density as a function of pressure. After being cured at room conditions, the resulting cement specimens were characterized in terms of compressive strength. Experimental data suggests that cement compressive strength is mostly independent of the lightweight microsphere strength and strongly dependent on the cement load. Guidelines on the selection of the appropriate microsphere grade are also presented.
Unconventional Resources Exploration and Development in the Northern Territory - Challenges from a Regulator's Perspective
Authors: Rezazadeh M.. , Hattum J. van , Marozzi D..
Published: October 2016

The production of conventional onshore oil and gas in the Northern Territory began in 1983 from the Palm Valley gas field, Amadeus Basin South of Alice Springs. Up until 2010the industry relied on conventional oil and gas development technology albeit with substantial technological advances over time. In recent years the focus of the industry has shifted to unconventional resource exploration, particularly the highly prospective shale gas resources in the McArthur and Georgina Basins. Current estimates indicate that the Northern Territory has more than 200 trillion cubic feet of prospective unconventional natural gas resources in six basins.

The technologies and techniques to explore and develop petroleum resources from deep shale are innovations on technologies and practices employed for exploration and development of conventional resources with revolutionary consequences, particularly in North America. Those techniques relate to innovations and improvements in horizontal drilling with greater precision and high volume hydraulic fracturing allowing for the development of source rock with extremely low porosity and permeability.

The scale and impact of the unconventional oil and gas industry in North America has led to increased public scrutiny of the oil and gas sector. In particular environmental concerns are being raised regarding contamination of potable water aquifers, sustainable water use and disposal of flowback fluids, induced seismicity, fugitive emissions, well integrity issues and Naturally Occurring Radioactive Materials (NORM) among socio-economic and moral issues. The Northern Territory Department of Mines and Energy (DME) continually adapts its procedures and regulatory framework to maintain effective regulation of the industry.

This paper outlines the key issues that must be addressed from a regulators perspective in regards to the development of an onshore unconventional gas industry in the Northern Territory and DME's approach to regulation and the challenge of maintaining a current legislative framework in a rapidly evolving and highly technical industry sector.
Enhancing Intervention Efficiency and Eliminating Uncertainty — First Ever Successful Conveyance of MWD Tools on CT for Multilateral Well Stimulation in a Middle Eastern Gas Well
Authors: Buenrostro Adrian , Arevalo Alfredo , Alzaid Mustafa , Abulhamayel Nahr , Driweesh Saad , Chacon Alejandro , Fadul Jose Camilo , Noguera Jose
Published: October 2016

Drilling technologies are constantly being developed as operators push the envelope limits to maximize reservoir contact and increase hydrocarbon recovery. These advancements in well construction challenge the well intervention community to seek innovative solutions to successfully intervene in these wells. This paper discusses the successful combination of a slim OD measurement-while-drilling (MWD) tool run on coiled tubing (CT) for real-time survey of the open hole lateral wellbore, followed by a stimulation treatment at appropriate depths for all laterals in a single CT run.

Saudi Arabia has been in the forefront of maximum reservoir contact well construction with the drilling of multilateral open hole gas wells; thus, the need for CT operations to enhance current offerings and procedures. For this application, several tests were performed to determine the feasibility of the combination of necessary tools to be able to steer, identify, and pump the stimulation treatment in a single run. MWD tools were run on CT in this multilateral gas well, and the stimulation treatment was performed during the same CT run.

The common practice in the study area was to run in hole down to total depth (TD) and determine, only by depth difference, in which lateral the CT was located. The uncertainty level increased exponentially when TDs of the laterals were within hundreds of feet because the treatment could potentially be performed in an alternate lateral, rather than the one intended (Ref 1-5). With the use of MWD tools that can relay inclination, azimuth, orientation (steering capacity), pressure and gamma ray, all this uncertainty is eliminated to help ensure a positive lateral identification for proper treatment placement in the well.

The MWD tool run on coiled tubing (CT), implemented a procedure explained in this paper to eliminate the uncertainty associated with previous technologies used for in real-time CT positioning inside the wellbore. The CT position is now reliable verified by survey match with real time readings from CT tip, allowing the certification of job placement in the desired wellbore path, to complete the intervention associated to the CT intervention; i.e.,: "a stimulation treatment" to be done specifically and independently for all laterals in a single run on each. This project open the doors for many other MWD-guided CT interventions to be applied in such conditions.
Justifying Appraisal in a Low Oil Price Environment: A Probabilistic Workflow for Development Planning and Value of Information
Authors: Walters Stuart , Ward Gavin , Wigston Bruce , Talluri Shyam
Published: October 2016

Appraisal adds value to potential developments by changing key development decisions (well count, subsea infrastructure requirements, development sequence, etc.), and this value can be quantified using value of information (VOI). The value of perfect information is readily evaluated but, unfortunately, all real world data is imperfect. Quantifying the value of this imperfect information requires assessment of either (i) the likelihood of the appraisal activity correctly resolving the value of an uncertainty, or (ii) the impact of the activity on the post-appraisal uncertainty range, both of which can be problematic. Traditional value of imperfect information analyses tend to focus on resolving only a single uncertainty and becomes difficult to apply as the number of uncertainties addressed by a single appraisal activity increases.

This paper describes a fit-for-purpose probabilistic approach to enable the rapid evaluation of perfect and imperfect value of information for a range of appraisal alternatives. The workflow is demonstrated through its application to a recent deepwater appraisal well which included an extended well test selected as the preferred activity from amongst a range of alternatives (including conducting no further appraisal).

The workflow uses a Monte Carlo spreadsheet tool to generate gas in place (GIIP) and estimated ultimate recovery (EUR) estimates for individual reservoir elements, which are then aggregated to field level estimates. A large number of individual trial values are captured and interrogated in conjunction with a set of heuristics to allow the rapid generation of probabilistic development plans (without needing to rely on a small set of deterministic realisations). Distributions and dependencies defined in the spreadsheet can be readily altered, enabling robust evaluation of the impact on EUR and preferred development plan for each appraisal alternative and outcome (low/mid/high). The EUR and development plan are then used in an economic model to quantify the value added by each appraisal activity. The highest value appraisal activity, in this case the appraisal well with an extended well test, was executed and a post-appraisal lookback was completed to review the value of information analysis once the appraisal results were available.
Managing Abandonment in Australia
Authors: Askew Philip , Bourdeau Christophe , Volkenborn Arnold , Lea-Cox Andrew , Charan Abhinav
Published: October 2016

Australia is an inexperienced player in field abandonments with early efforts proving complex, high cost, and with last minute approvals due to regulatory and social concerns. Whilst many companies are on top of the costs, they are often isolated from the latest innovations or focused on the next 2-3 years operations. Looking forward, abandonment expenditure will accelerate and be sustained with most companies active and more coming (e.g. Bass Strait, Rankin etc.). Between 2016 and 2030, the overall impact of decommissioning is estimated at $5 billion to $7 billion with the government exposed to up to 60% of this cost through taxes or higher if left with the liability. Considering uncertainty in the regulations, the industry, NOPSEMA and the Government need to deal with what can be left on the sea floor, NORM-related disposals, handling onshore and transfer of liability. Their duty is to protect the environment, provide the platform for safe operations, maximise value for stakeholders but also avoid the taxpayer bearing increased costs/rebates from inefficient programmes. On the cost side, many companies are looking to upgrade abandonment capabilities, and take advantage of new technologies and approaches. However, capabilities and experience are short and regulations unclear. Even so, not all will be equal in their diligence and provisions and hence we are likely to see missed opportunities as an industry. Looking at case studies in Gulf Coast, North Sea and Australia tells us there are many lessons learnt and successes that we should be employing from both environmental and cost angles – e.g. most abandonments struggle with unclear regulations and well/facility deterioration and barrier issues. With these challenges and risks, leadership from all stakeholders should come together to better define and select innovative concepts for decommissioning that moves to sustainable, acceptable and high-value solutions for all stakeholders in the coming years.
Enhancement of Structural Conductor Design and Execution of Jetting Operations for Ultra-Deepwater Wells in Brunei
Authors: Syazwan M , Shafei A , Paimin M Razali , Su'if M Zyden , Abidin Hj Zainal , Ismail Yussof , Natarajan S..
Published: October 2016

Structural casing or conductor pipe provides a foundation for deepwater well and is designed to withstand the expected axial and bending loads. A very conservative design approach with worst case scenario is usually adopted for structural casing in exploration wells because the lack of information and high risk associated to deepwater operations cannot be underrated.

This paper will present the evolution from a conservative to a fit-for-purpose engineering design approach. A design review with the latest interpretation of regional geological understanding derived from actual drilling experience was performed to quantify the associated uncertainties in the design phase. The result was compared with an independent analysis and validated during the actual installation performed by rig contractor. The project team supplemented this paper with a case study by sharing the conductor installation results from the jetting operation.

In the early stage of deepwater exploration wells in Southeast Asia (SEA) region, many operators set their first string or structural /conductor pipe at around «80 m below mudline. This is a normal industry practice adopted from experiences in the GOM deepwater operation or operators' own experience in their deepwater field. This structural casing is generally jetted down with internal jetting BHA and drilled in riserless mode to the predetermined depth. This first string will not be cemented, and a subsequent surface casing will be installed and cemented to seabed. These two (2) strings will provide the foundation for a deepwater well to withstand the expected load, which are axial loads and bending loads. The conservative design generally uses a large size structural pipe like 36 in. OD with wall thickness from 1.5 in. to 2.0 in. WT. The second surface casing typically uses a large size pipe like 20 in. OD with moderate wall thickness. A weld-on connector are generally used for both structural and surface casings to accommodate the expected axial and bending load resulting from the installation of BOP and marine riser. The paper will describe the progression and transformation from the conservative to a fit-for-purpose design by optimizing the structural casing setting depth, its wall thickness and employing slim well architecture specifically for shallow well objectives below mudline. The most significant finding is that the slim design has proven to be suitable and was successfully installed in three (3) ultra- deepwater exploration wells in Brunei. This paper also will share the Company's experience and observation during the structural conductor installations to achieve efficient execution during jetting operations.

The novelty of the fit-for-purpose design is in the ability to change the design norm resulting in substantial cost savings to the company and meeting the well objectives.
Deepwater HTHP Drilling Fluid Development and Field Applications in Western South China Sea
Authors: Liu Hexing , Li Zhong , Huang Yi , Fang Manzong , Liu Zhiqin
Published: October 2016

Dozens of deepwater wells have been drilled in western South China Sea with about 30 percent have characteristics of high temperature and high pressure, which brought a series of difficulties and challenges to field operations. After incorporating the analysis of engineering and geological environment for deepwater HTHP wells in Lingshui block of western South China Sea, it is suggested that the solution of drilling problems for deepwater HTHP wells should start from drilling fluid. Several major technical problems are required to be addressed by drilling fluid, such as co-exist of low temperature and high temperature that lead to difficulty of drilling fluid maintenance and narrow density margin caused by deepwater and high pressure. Based on the above problems, combining with geological features of HTHP wells, researchers developed a novel water based drilling fluid system compatible with deepwater HTHP wells in Lingshui block on the basis of conventional HEM drilling fluid and further optimization. It has been recently applied in three wells and as can be seen from the application results, this system greatly reduced the incidence of complex situations in deepwater HTHP wells and gives consideration to the conflict of high temperature and low temperature. It can also be compatible with temperature difference and increase holding pressure.
Overcoming Challenges in Pore Pressure Prediction and Wellbore Stability in Brunei Ultra Deepwater Exploration Well Campaign
Authors: Omar M Mizuar , Rasli M Faiz , Paimin M Razali , Maulana Herry , Ghosh Amitava , Abidin M Zyden
Published: October 2016

Pore pressure prediction and geomechanical modelling play a very important role in well planning and is one of the many challenges facing the oil industry today, as exploration focus worldwide is moving more and more into the deep-water environment. Pressure related problems in deepwater wells are mainly associated with narrow operating window resulting in severe well control incidents, sometimes even leading to early abandonment. A better understanding of the prevalent pore pressure regimes in terms of generating mechanisms along with pressure maintenance and dissipation through geologic time offers invaluable insight and perception about these challenges and also on our ability to predict and mitigate or minimize them. Borehole instability related problems like excessive wellbore breakout can result hole cleaning issues, stuck pipe, setting casing earlier or potentially losing the wellbore. It is important to analyze these challenges and develop an understanding of the same, prior to drilling so that, various plans and mitigation systems can be put in place.

A substantial amount of non-productive time (NPT) was associated during the initial phases of drilling campaigns in the Brunei deepwater. Accurate mud weight window prediction using regional scale pore pressure prediction and geomechanical modeling clearly demonstrated a significant reduction in nonproductive times over the different phases of drilling campaigns till date. This also includes a regular update or refinement of the model as soon as new data or information becomes available.

This paper presents some of the methodologies used during well planning and construction of deepwater and ultra-deepwater wells. It also discusses the work refinement throughout each drilling campaigns, which resulted in improvement on geological and geomechanical model. It is imperative to note that the intent is to document and share experiences and lessons learned in Brunei deepwater wells within the industry. This would enable the execution workflow and well design to be continuously improved for a safe and cost-efficient delivery of the wells.
Tests to Compare the Performance of Zinc and Steel Big Hole Charges: First of its Kind in an HP/HT Setting
Authors: Haggerty D.
Published: October 2016

Using the upgraded capabilities of the perforation flow laboratory, and after some trial and error, tests were successfully conducted designed to compare zinc and steel-cased big hole (BH) shaped charges at bottomhole conditions. In the past, conducting perforation performance tests that included wellbore control were limited to matching reservoir pressures up to 5,000 psi. These tests were conducted at conditions representative of a Gulf of Mexico (GOM) reservoir exhibiting 17,200 psi overburden stress, 9,100 psi pore pressure, and a temperature of 210°F. Completion plans include setting the wellbore pressure at 10,550 psi before perforating to create a static overbalance of 1,450 psi. Aligned with American Petroleum Institute Recommended Practice 19B (2006) Section 4 (Rev. 2014), the tests were conducted to closely match the perforating portion of the completion design in the oil-producing field to provide an effective physical simulation. The outcome provides useful perforation performance data, including flow into and out of the perforation.

Many design modifications from previous ambient, limited pressure Section 4 tests were necessary to successfully conduct the tests at the higher GOM reservoir pressure and 210°F. This paper discusses the difficulties encountered during testing and how workable solutions were achieved to perform such tests. Reinforcing the integrity of the soft, producing formation analog core without reducing the effective stress was the most significant challenge encountered during this study. Sustaining steady flow at pressures higher than the limits of the available high-accuracy pressure transducers and flow meters also required a new approach. The net result of this effort revealed that penetration depth differed less that previously assumed between the zinc-cased charge and the steel-cased charge at the experimental conditions and setup used in the tests.

The development of perforation testing laboratories has allowed the capability to shoot any shaped charge in a simulated wellbore environment at elevated temperatures and high pressures, matching virtually any reservoir in the world.