Near Real-Time Geomechanical Model Update and Completion Optimisation in the Fold Belt Area of PNG: A Case Study with Oil Search Ltd

This talk outlines the workflow and displays some results from the Papuan Fold Belt Area.

Without major changes in energy-related policies, the world’s energy demand will grow by more than 50 % over the next two decades, and will continue to be dominated by fossil fuels.

Options for an “energy revolution” in both the energy demand and the energy supply sectors are presented. Scenarios for the deployment of a new energy portfolio are discussed, including ones that would lead to a reduction of emissions by 50 percent in 2050.

Dr Andrew Wadsley, Bsc (Hons), Director Stochastic Simulation Ltd.

A brief and simplified background will be given on how a fractured rock mass is characterised from a Geomechanics point of view. This talk will demonstrate the importance of integrating Geomechanical studies as part of the field development plan.

Unconventional Frac Jobs for Unconventional Reservoirs:
What Should You Be Concerned About?

Unconventional reservoirs are just that – unconventional. Extrapolation of techniques that have been used for decades in conventional reservoirs to unconventional reservoirs is dangerous and can prevent further development by providing poor results and turning funding away to “safer” areas. This sequence of events can be observed at all levels of petroleum engineering, from petrophysics to reservoir analysis to stimulation techniques.

In order to avoid such misapplications, unconventional reservoirs call for unconventional thought processes. In no place is this more evident than in the area of hydraulic fracturing, where an entirely different mindset has to be developed, not just for unconventional reservoirs in general, but specifically for each individual type of unconventional reservoir including shale gas, tight gas, and low permeability oil.

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Modeling Complex Reservoir Geometries Accurately: Using the Right 3D Grid Types

Subsurface modeling requirements have changed significantly over recent years: higher oil prices have made exploration and development of more complex reservoirs feasible; and substantially more data is available for predicting and monitoring performance. It becomes an opportunity but also a challenge to integrate this data in more sophisticated subsurface models for better decision-making. Targets for development have become more (structurally) complex, and thus depend more critically on accurate models of geometry. This presentation attempts to analyze the requirements of geological and dynamic modeling, covering fluid flow as well as geo-mechanical responses to changes in the reservoir.

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Abstract

The One Idea: Taking even modest steps towards implementation of smart technologies can yield considerable benefits to underground gas storage operations.
Included in the presentation are case studies showing how real-time data is used to identify damage in storage wells and how the implementation of novel optimization and surveillance techniques have improved performance of underground gas storage facilities. An example of operations that integrates several levels of smart technology is also presented.

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The Van Gogh Developement

The Van Gogh development is a new FPSO project 60km offshore from Exmouth in Western Australia.  The thirteen well, all horizontal subsea project started in February 2010 and reached a peak rate of 73,000 bopd in March. This talk will cover the history of the field, provide an overview of the development, the construction of the multi-lateral wells and move on to cover start-up and a review of performance.

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Putting the Focus on Data

Data is a critical business asset which drives decisions on where to invest, when to divest and how to operate more efficiently. The business wants to focus on using data and expects IT to manage data. However, IT often focuses on the technology to capture, store data and even to visualize data but the ownership of the lifecycle of data is often ill defined.

This presentation offers examples of a number of important components in the dynamic modeling process and why failing to attend to them can result in optimistic prediction.The intent of the author is to emphasize that the number of grid cells in a model should not be a substitute for the number of brain cells used during its construction.

Peter Hogg

This presentation will cover the characterization of unconventional reservoirs, particularly shales and coals, describing the considerations when taking samples for lab testing, rock tests to perform, the construction and calibration of the 1D MEM, borehole stress test considerations and inputs for frac design.

The talk will focus on how commercial multiphase transient numerical simulation software has been applied to support three different projects at Eni Australia, namely Woollybutt oil project, Blacktip gas project and Kitan oil project. Each project has its unique engineering challenges and therefore the application of the software has also been unique to each project.

The Pyrenees Development comprises the concurrent development of three oil and gas fields; Ravensworth, Crosby and Stickle. The fields are operated by BHP Billiton and are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin. The project is one of the largest offshore oil developments in Australia for some time and involved drilling and completion of seventeen subsea wells tied back to a disconnectable FPSO. First oil was achieved during February 2010.  This presentation gives an overview of the field development, describes the engineering and technologies that have been selected to enable the economic development of the Pyrenees fields, and furthermore demonstrates their contribution to continuous production optimisation.

Increased activity in drilling and completing natural gas wells has put new pressures on available water resources to support market growth.  Whether it be for tight shale gas plays or coal bed methane applications, a large amount of water can be required for well completion.  Typically, 10 - 40+% of the injected water resurfaces within a few weeks of well completion; over longer time more water will be produced, although at reduced rates.  With increased resource and environmental pressures, reclaiming and/or recycling flowback and produced water has become a focal point for the industry.  This presentation will review various water treatment technologies and environmental considerations for recycling and reclaiming flowback and produced water.  A main focus will be on discussing the pros and cons for each treatment technology category, and how those technologies fit the overall economic and environmental objectives for the overall water cost.

Prelude and Concerto have around 3 trillion cubic feet of liquids-rich gas.  The relatively small size of the gas fields and the remote location make them an ideal candidate for development via Shell's FLNG technology as it would not be economic to develop the gas via a conventional onshore LNG processing plant.

FLNG technology is an important development for the LNG industry as it reduces both the project costs and environmental footprint of an LNG development, because there is no need for long pipelines to shore; compression platforms to push the gas to shore; nearshore works such as dredging and jetty construction; and onshore development such as building roads, laydown areas and accommodation facilities.

There are currently no FLNG facilities deployed anywhere in the world, so Shell's Prelude FLNG Project is likely to be the world's first.  For Australia, the Prelude FLNG project will demonstrate a means of developing some of Australia's "stranded" offshore gas reserves - those considered uneconomic for development via an onshore plant because they are too small or remote. The CSIRO estimates Australia has around 140 tcf of stranded gas.

Well testing has been a core technology in the oil industry for decades because it provides in-situ measurements of dynamic well and reservoir data. Traditional results of pressure transient analysis included the average formation permeability and pressure, and the well skin and deliverability. As technology advanced over the years, better interpretation methods, more accurate testing tools with sophisticated features and substantially improved computers and software became available to help petroleum engineers design and analyze transient tests and manage their fields. 

In this presentation, field examples are used to illustrate the use of advanced technologies in transient data measurements (such as permanent downhole gauges, real-time data transmission and downhole shut-in tools) and data interpretation methods (such as numerical well testing, multiphase test analysis, multilayer test analysis and production data analysis). We will demonstrate what has been achieved so far and why well testing is now more valuable to petroleum engineers as a mean to improve management of oil and gas fields.

Unlike oil development, gas development is often constrained by contractual obligations. As fields mature, gas supply constraints typically switch from contractual obligations, to network facilities and ultimately to the subsurface performance. This presents a challenge to ensure that developments are sanctioned, major capital projects are executed and producing reservoirs are optimized to achieve an optimum asset management. Tackling this problem requires an integrated modelling approach and the Petroleum Experts’ Integrated Production Model (IPM) suite of software is widely used in the E&P industry for this purpose. There is a lot evidence in the literature that shows IPM applications in such diverse areas as field development planning, integrated forecasting, surveillance and production system optimization. Perhaps less reported are the lessons learned and best practices in using IPM.

This presentation describes some of the best practices and lessons learned in constructing and maintaining IPM models for some of Chevron’s largest gas fields. Examples cover all aspects of the IPM from the non-technical (e.g. framing the problem, case definition and naming convention) to the technical (e.g. model construction, model maintenance, software limitations, constraint violations, production optimisation and quality assurance checks).

An Oil & Gas project will probably have a lifespan of decades and demand capital investment of billions of dollars. When considering Foreign Direct Investment in an Oil & Gas project, the investment should be protected for the life of the project and be capable of surviving everything that man and nature may set in opposition. 

This presentation highlights some of the factors that should be considered when investing in major projects in the developing world. In particular, it highlights sovereign risks that should be expected when investing in resource (oil and mineral) projects. Presentation Abstract

Over the past years, E&P expenditures have almost tripled with only a marginal increment on world's production, 8% of which is attributed to deepwater fields. Deepwater wells have always posed technological challenges in the industry. From a cementing perspective, a number of significant issues need attention in order to bring deepwater cementing to a higher level of field performance and reliability. Shallow water flows, bottomhole temperature modeling, laboratory testing standards and cementing equipment specifications are a few of the topics which have to be managed. Today, we continue to see increasing costs and logistical difficulties, tougher environmental standards and regulations on the deployment of chemicals in sensitive environments combined with the requirements for fit-for-purpose cement designs. As drilling expands into remote areas, with narrow drilling windows for which planning, logistics and on-site decision making will play a more critical role, selecting adequate enhanced cement systems that can be adapted to variations in density and temperature will be critical to the success of these operations.

Coupled reservoir flow and geomechanics simulations are important in many compositional fluid flow processes like water-alternating-miscible gas injection and CO2 storage. The intention in these models is to understand the effect of stress and deformation consequent to changes in reservoir flow and fluid phase behavior. Safe CO2 storage in deep saline aquifers calls for evaluation of cap-rock and seal integrity via stress responses so that undesired leakage through the seals could be avoided. In the geomechanics calculations unknowns at a large number of finite element nodes need to be solved at each coupling step, which can lead to overwhelmingly large computation time for the coupled simulations. 

This talk presents an extension of the above method wherein the geomechanics model is coupled with an equation-of-state compositional simulator in place of a thermal simulator. Use of the dual grid system is demonstrated through simulation models for two compositional processes (CO2 WAG EOR and CO2 Saline Aquifer Sequestration). Comparison between a dual grid system and a single grid system is presented. The results show that there is substantial saving in computation time and memory requirement without significant loss in the quality of flow or geomechanical results

The complex geological architecture in deepwater turbidite reservoirs, coupled with multi-billion dollar development schemes (i.e., dry or wet tree wells, subsea pipeline system and floating facilities), makes field development planning a very challenging task. The reservoir engineer is often faced with tough questions: “How many wells are required?” and “What is the reserve volume and its range?” To answer these questions requires a complete assessment of risk and uncertainties of the reservoir to be developed. Even with the most rigorous technical approach, the uncertainties will remain. It is equally important to communicate the risk and uncertainties to key stake holders so that an informed business decision can be made. This lecture will discuss a systematic approach to frame the risk, link the risk to uncertainties, assess the uncertainties and develop an activity plan. The activity plan should be tied to reservoir surveillance program so that risk is mitigated and the uncertainties are reduced as the project moves into execution and production phases. Key takeaway from this presentation is to keep risk and uncertainties analysis simple by looking at the big picture and only focus on the uncertainty parameters that have a material impact on the business. A few examples of a field development plan will be discussed in the lecture.

Over the past years, E&P expenditures have almost tripled with only a marginal increment on world's production, 8% of which is attributed to deepwater fields. Deepwater wells have always posed technological challenges in the industry. From a cementing perspective, a number of significant issues need attention in order to bring deepwater cementing to a higher level of field performance and reliability. Shallow water flows, bottomhole temperature modeling, laboratory testing standards and cementing equipment specifications are a few of the topics which have to be managed. Today, we continue to see increasing costs and logistical difficulties, tougher environmental standards and regulations on the deployment of chemicals in sensitive environments combined with the requirements for fit-for-purpose cement designs. As drilling expands into remote areas, with narrow drilling windows for which planning, logistics and on-site decision making will play a more critical role, selecting adequate enhanced cement systems that can be adapted to variations in density and temperature will be critical to the success of these operations.

  The talk presents a perspective on CCS globally and in Australia, illustrating the issues and highlighting project development factors causal to the success. Fossil fuel usage is projected to grow and logically CCS should have significant potential. For storage the technology is not a limitation, the policy framework is being created in several jurisdictions and significant effort is being put towards building community support. Making a business case remains a hurdle and innovative options for generating revenue streams from CO₂ are being considered. The oil and gas industry has the knowledge and experience needed to define and develop storage options. These need to be suitably leveraged and there is an opportunity window over the next few years in which CCS if proven at scale can make a major impact on green house gas mitigation in the future.

SPE Luncheon Abstract and Flyer

The Australian Oil & Gas industry is undergoing an unprecedented capital investment cycle characterized by many technological firsts, massive scale, operational complexities and business and economic challenges.  Despite these challenges, companies will be expected to meet all strategic, operational, economic, environmental and safety goals.  What are the critical focus areas that companies must get right to be successful?  How can new organizations that have never operated in Australia before be prepared for flawless start up and safe and efficient operations?  These questions are keeping many in our industry awake at night.  In this presentation, we will discuss the critical focus areas and describe a roadmap to help companies get ready for the future. 

Hallin, with its joint venture partners Minnow Marine Projects Ltd. and STX Canada Marine Inc. (formerly Aker Yards Marine), has developed a vessel design that responds to the need for greater flexibility. This design also provides solutions in both subsea services and well intervention, along with a variant for high occupancy accommodation.

The vessel is designed to provide multiple subsea services that support the operators’ desire to improve production and reduce costs, with motion characteristics that significantly exceed that of similar length units. Of particular note is the compliance with MODU regulations and guidelines. Typically, a traditional vessel would not need or be able to comply with these requirements.

The presentation will discuss the reasoning and design process, tank trials and outcomes as well as briefly present the capability and final build status as it is today.

Absract

Drilling, completion and production from wells passing through depleted reservoirs and interbedded weak formations can be a challenge. Pressure depletion in reservoir sections causes a decrease in the fracture gradient. Interbedded non reservoir sections, however, require a higher hole pressure to maintain the wellbore stability while drilling and during life of the with open hole completion.
A workflow for building and updating geomechanical model is presented with applications for wellbore stability analysis, sanding evaluation and selection of optimum completion for a number of wells in two fields. 

Full Abstract

Located offshore near Dampier in WA, the Julimar Development Project (JDP) is a subsea development that will supply raw gas from the Julimar and Brunello gas fields to the Wheatstone Project. Apache Energy currently hold a 65% share in the Julimar project and are responsible for its operation and management, including drilling of wells and installation of the subsea facilities.

In this session Allan will provide a technical overview of the development from the reservoirs through the infrastructure to the delivery point at the Wheatstone platform. At the same time Allan will highlight how some of the key technical challenges, such as development of the multiple stacked reservoirs, are being managed. 

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Technologies for optimization of reservoir management strategies have made significant advances in the areas of real-time reservoir monitoring, interval flow control, and downhole flow measurements. The petroleum industry has moved closer to real-time reservoir management by combining applications of these revolutionary technologies to improve economic recovery of hydrocarbons.

The main idea that SPE members can take away from this lecture is that new technologies are available that could significantly improve hydrocarbon recovery from new and brown fields by incorporating these technologies in their reservoir management strategies.

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Unconventional gas has the potential to transform the Australian energy landscape. However there are many complex technical, commercial and policy-related challenges to overcome to ensure that this potential is realised. Allens Partners Anthony Patten and Tracey Greenaway will lead a discussion on some of the legal and regulatory issues to be considered in the context of an unconventional development.

The Chevron-operated Wheatstone Project is one of Australia’s largest resource projects. It is a $29 billion integrated LNG development currently entering construction. It comprises subsea wells and flowlines, an offshore platform, a trunkline, 2 liquefied natural gas trains (with a combined capacity of 8.9 million tonnes per annum) and a domestic gas plant. 

Mark will discuss the different technical design challenges and how they were addressed, including the various initiatives used to manage safety and weight.

A full life-cycle integrated approach for shale resource plays is an essential process to establish value creation and to ensure reserves and production growth.  With this process key issues and uncertainties in shale resource development are resolved as plays evolve from concept screening; to exploration and resource assessment; to full development.  The integrated approach relies upon key elements which include 1). Field Demonstrations and 2). Mechanistic Studies.

The design, planning, and implementation of systematic and "scalable" Field Demonstrations are essential elements required to address strategic, development and operational issues.      Mechanistic studies are utilized to understand the key production drivers.  Shale gas productivity is typically much lower than conventional reservoir systems and often lower than tight gas reservoirs.  The flow behavior in these systems must be understood and quantified in order to effectively characterize and predict well and reservoir performance behavior.  The primary take-away from this presentation is that new processes and advances in field demonstrations and mechanistic models are key factors required for appraisal and development of global shale resources.

The major Oil and Gas Projects in Western Australia have created significant opportunities for local industry to join the supply chains of international project proponents and EPCMs.

Jonathan Smith will describe the growth of the AMC CUF and demonstrate how local industries have benefitted from the $400m of Government investment in major industrial common user infrastructure to enter markets previously out of their reach. The AMC CUF in Henderson is in the heart of Western Australia’s manufacturing region and will have been in operation for ten years in July this year.

Although focusing on the Oil and Gas Projects, Jonathan will also show how the Defence, Marine and Mining industry sectors have used the facilities.

The major Oil and Gas Projects in Western Australia have created significant opportunities for local industry to join the supply chains of international project proponents and EPCMs.


Jonathan Smith will describe the growth of the AMC CUF and demonstrate how local industries have benefitted from the $400m of Government investment in major industrial common user infrastructure to enter markets previously out of their reach. The AMC CUF in Henderson is in the heart of Western Australia’s manufacturing region and will have been in operation for ten years in July this year.

Although focusing on the Oil and Gas Projects, Jonathan will also show how the Defence, Marine and Mining industry sectors have used the facilities.

Cost and schedule over runs continue to characterise major E&P projects. Rationalisation of this erosion of shareholder value is typically blamed on forex, product escalation, productivity and even weather. RISC disagrees. While these factors may be contributors we believe the primary drivers of poor capital efficiency are psychological issues. Based on investigation and research covering the last 40 years RISC believe that cognitive and motivational bias are substantial contributors to major project cost and schedule over runs

Experience from North America shows that water management in shale development is a complex subject. There are as many different strategies being pursued as there are shale plays, regions, and operators. If not handled properly, the permitting, acquisition of fresh water, reuse, recycling, and disposal of water can be expensive and can result in project delays. Likewise, regulations that do not adequately consider the realities of water management lead to inflated costs, inadequate protection of the environment, and detrimental impact on local communities.

In this presentation, the historical experience from North America will be presented and examined from the standpoint of the total cost and total impact of water management operations. Examples of existing water treatment and management practices will be discussed. To achieve an understanding of total cost and impact, a cradle-to-grave or holistic approach is required. Individual costs of specific water management operations are often inadequate in developing a viable strategy since lower cost in one operation may lead to much higher costs in another. A similar situation is true in considering the environmental and community impacts. In taking a holistic view, it is possible to gain direct insight into what has happened in North America in various plays, why the industry has evolved in various directions, and it may be possible to get a sense of the future direction of the industry.

Natural gas liquefaction is a series of refrigeration systems similar to the air conditioning system in our homes consisting of a compressor, condenser and evaporator to chill and condense the gas.  The difference is in the scale and magnitude of the refrigeration.  A typical single-train LNG plant may cost $1.5 billion and consume 6-8% of the inlet gas as fuel.  Since many of the impurities (water vapor, carbon dioxide, hydrogen sulfide, etc.) and heavier hydrocarbon compounds in natural gas would freeze at LNG temperatures, they must first be
removed, and disposed or marketed as separate products. 

This presentation will provide an overview of LNG liquefaction facilities, from inlet gas receiving to LNG storage and loading.  However, the focus is on the liquefaction process and equipment.  Differences among the commercially available liquefaction processes (cascade, single mixed refrigerant, propane-pre-cooled mixed refrigerant, double mixed refrigerant, nitrogen, etc.) will be discussed.  The aim is to provide SPE members with a clear understanding of the technologies, equipment and process choices required for a successful LNG project.