Dear fellow SPE members,
As we head into the final quarter of 2018, all of you will be receiving your SPE dues for membership of our Society for 2019. Please consider paying your dues soon and participating in our Society in the remainder of this year and into 2019
There are several benefits of membership of SPE:
The membership committee (Vesna, Adrian, Matt) of the Western Australian SPE section are looking for opportunities to enhance the value of your membership going forward. Please reach out to us if you have some ideas you wish to contribute.
Matthew Flett, SPE WA membership chair.
The 2018 SPE Asia Pacific Oil and Gas Conference and Exhibition will be held in Brisbane 23rd to 25th October. Registration for this conference is through the SPE website here: https://www.spe.org/events/en/2018/conference/18apog/asia-pacific-oil-and-gas-conference-and-exhibition.html
Selected abstracts from papers to be presented at the conference have been released by the authors and technical programme for the conference below. Consider registering for the conference to attend these selected papers:
Geomechanics: A Key to Understanding the Underperformance of Fracture Treatments. Khalil Rahman, Baker Hughes, A GE company
Discrete Net-to-Gross Truncated Gaussian Simulation: An Alternative Modelling Approach for CSG Unconventional Reservoirs, Bowen Basin, Eastern Australia. Simone Rattazzi and Alan Hansen, Santos Ltd.
Planning and Drilling Execution of Early Permian wells in two string design by implementing new drilling and cementing technologies. Alex Shaban, Mohammad Zaman and Thivanka Dedigama, Santos Ltd.
Advantages, Challenges and Selection Criteria (Queensland Case Study). A. Mortezapour, A. Bassatt and E. Lean, Weatherford Australia
Use of Probabilistic Methods to Assess a Portfolio of Conventional and Unconventional Resources. Alistair Jones, Chris Mijnssen, Andrew Burton and Mark Ewin, Origin Energy.
Risk Factors Affecting Delays in Upstream Natural Gas Mega-Projects: An Australian Perspective. Munmun Basak, Vaughan Coffey and Robert K. Perrons. Queensland University of Technology.
Application of Ensemble Variance Analysis in the Development of the Wheatstone Field Startup Strategy. Matthew Flett and Paul Connell, Chevron Australia.
Improving Outcomes for Oil and Gas Projects through Better Use of Front End Loading and Decision Analysis. David Newman, Steve Begg and Matthew Welsh, University of Adelaide.
Impact of Laboratory Testing Variability in Fracture Conductivity for Stimulation Effectiveness in Permian Deep Coal Source Rocks, Cooper Basin, South Australia. Samuel A. Fraser, Santos Ltd. Raymond L. Johnson Jr, University of Queensland.
Calibration of Sand Production Prediction Models at Early Field Life in the Absence of Sanding Data. Ahmadreza Younessi, Abbas Khaksar, Feng Gui and Sadegh Asadi. Baker Hughes, a GE company.
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Selected abstracts from the upcoming SPE APOGCE are presented below. Register for the conference here: http://www.spe.org/events/en/2016/conference/16apog/registration.html
Optimization of Steamflooding Heavy Oil Reservoirs under Uncertainty. SPE 182190
Cenk Temizel, Aera Energy, Afzal Iqbal, University of Western Australia, Karthik Balaji, Rahul Ranjith, University of Southern California
Conformance improvement is the key to success in most enhanced oil recovery (EOR) processes, especially CO2 foaming or steamflooding. Despite technical and economical restrictions, foam has been used as dispersions of microgas bubbles in the reservoir to help improve mobility. Steam-foam has many applications in the industry, including but not limited to heavy oil reservoirs, which are an important part of the future energy supply. Steam-foam applications have been used to help prevent steam channeling and steam override, thus improving overall sweep efficiency, not only in continuous steam but also in cyclic steam injection processes. Due to the high temperatures achieved during steamfloods, a robust understanding of chemistry including the thermal stability of surfactants is important.
The effectiveness and therefore economics of the steam-foam process are strongly dependent on surfactant adsorption and retention. With that in mind, effective sizing of the foam injected requires a good understanding of the process. In this study, a reservoir simulator is used in which surfactant transport is modeled with surfactant availability determined by a combination of surfactant adsorption, surfactant thermal decomposition, and oil partitioning due to temperature. A robust commercial optimization and uncertainty tool is coupled with the reservoir simulator to generate the scenarios defined by control variables for optimization and uncertainty parameters for sensitivity analysis.
The degree of mobility reduction is interpolated as a product of factors that include aqueous surfactant type and concentration, presence of an oil phase, and the capillary number. An empirical foam modeling approach is employed with foam mobility reduction treated by means of modified gas relative permeability curves. Simulation results including the sensitivity of parameters and controlling agents, providing a better understanding on the influence of surfactant adsorption and thus the amount of chemicals to be used, are presented and discussed to serve as a guide for future applications.It is not easy to find documented examples of realistic optimization studies where significance of each control and uncertainty parameter is outlined and discussed using a realistic reservoir model. The simultaneous use of optimization and uncertainty led to a better understanding and thus control of decision variables in varying ranges of uncertainty that will be useful in analyzing prospective assets.
How to Age Gracefully – Pipeline Life Extension. SPE 182262
Allison Selman, Atteris Pty Ltd Rex Hubbard, Atteris Pty Ltd
This paper presents the engineering process for performing a design life extension study (or design requalification) for an offshore pipeline system. The principles and process however, could be applied to design requalification of any physical asset.
Every pipeline system is designed for a theoretical maximum duration called its design life. In some instances there may be a requirement to continue operations beyond this date. This paper provides guidance on the technical life extension processes and procedures and it focusses on the engineering that is required to provide adequate assurance for safe continued operations.
This paper presents the two main international guidelines that are typically used: NORSOK Y-002 and ISO 12747. The life extension process will be discussed step-by-step with guidance on technical considerations at each stage.
A case study example is used to demonstrate how the process has been applied to assess the fitness for service of an offshore pipeline system for an additional 10 years. The case study describes some of the key engineering assessments which may be required to support the life extension assessment and includes an example of a probabilistic corrosion assessment that enabled deferral of a high cost subsea-to-shore inspection pigging campaign.
Pipeline life extension opens up many development opportunities, especially in challenging economic conditions. If a pipeline can be re-used or re-purposed for future developments then significant CAPEX reductions can be achieved for small, nearby developments. To enable this opportunity the risks of continued operation must be fully understood following a systematic and comprehensive approach to assess the risks. Once the risks are understood then they can be adequately managed through a proactive integrity management program.
The Importance of Collaboration, Integration, and Relational Database Management for Vast Corporate Data: A Case Study in Indonesian National Oil Company. SPE 182299
Nora Desiani, Nur Alam, and Freddy Yulisasongko, Pertamina Hulu Energi, Adeline Susanto, Andrean Satria, and Ade Veria Octora, Halliburton
The asset management of an Indonesia’s national oil company has become complex and challenging because every field acquisition and takeover becomes its new asset (subsidiary). Challenges, such as standard corporate database (e.g. cataloguing), seamless workflow in retrieving massive data, data retention ability, and cartographic reprojection lead to a need for data management optimization and integration, which must be securely and reliably managed.
Smart vision methodology migrates architecture from an existing system to a new integrated system. Workflow consists of steps designed to gather information, engage the customer in a collaborative manner, and assemble opportunities into an orderly plan that has strategic alignment and cost benefit justifications for each case. The approach used by the company refers to professional petroleum data management (PPDM) data model, which puts collaboration, integration, and relational database management forward. Deployment of this model results in standardization of corporate database. Previous different data configurations will then have a standard cataloguing system, which results in consistent data retrieval.
Smart vision methodology is applied to capture and study the company’s existing architecture. A major finding is tremendous data from each of its subsidiary has its own standards and contains structured and unstructured data, which makes it troublesome for analysis to further determine best business decision. History data, data retention, and data permission management are very arduous and implausible. Distortion of cartographic projection data makes the data itself nonscalable. To overcome these challenges, PPDM data model is deployed. Data mapping is performed on 18 the NOC’s subsidiaries’ data. Company preference, policies, and regulations are standardized at corporate level. As a result, an integrated database is being established. Corporate can see all assets in a single project database, which allows further technical analysis and eliminates data duplication problems, making the data manager easy to manage. From user management’s point of view, the presence of the interpreter source priority (ISP) concept allows user collaboration without disrupting either corporate data or other user’s interpretation. Another result is user ability to track historical data. This is important for corporate; thereby, users can access not only interpretations results but also other users’ knowledge content.
The deployment of this model gives ability to manage all the seismic, well, and interpretation-related data into one consolidated project regionally in scalable geographical area and complexity. This allows the company to perform various analytics process related to all data owned by the company.
Improving the Conductivity of Natural Fracture Systems in Conjunction with Hydraulic Fracturing in Stress Sensitive Reservoirs. SPE 182306
Alireza Keshavarz, Ray Johnson, Jr., Themis Carageorgos, Pavel Bedrikovetsky, Alexander Badalyan, Australian School of Petroleum, The University of Adelaide, Adelaide, Australia
The technology of injecting micro-sized proppant particles along with fracturing fluid is proposed to improve the conductivity of naturally fracture systems in stress sensitive reservoirs, by placing graded particles in a larger, preserved stimulated reservoir volume around the induced hydraulic fracture (Fig. 1). One of the main parameters determining the efficiency of the proposed technology is the concentration of placed proppant particles in the fracture systems. A laboratory study has been conducted to evaluate the effect of placed proppant concentration on coal permeability enhancement using injection of micro-sized proppant into coal core and varying effective stress. Permeability values are measured for different concentrations of placed particles as a function of effective stress (Fig. 2). There is an optimum concentration of placed particles for which the cleat system permeability reaches a maximum, further permeability enhancement is more sensitive to concentration of placed proppant at higher than lower effective stress (Fig. 3). The maximum permeability enhancement by 3.2 folds is observed at effective stress of 950 psi.
In a field application, the determination of all cleat apertures to optimize particle sizing will be difficult and unlike the core test, the effluent concentration cannot be derived once the fluid leaves the hydraulic fracture and travels into the cleat or fracture network. In some cases, the distribution and mean values for cleat or natural fracture aperture can be estimated from: physical core observations; imaging tools; and pressure transient tests to derive dual-porosity parameters; from these, a matchstick model for matrix blocks and regular fracture arrangement can be constructed.
In the field, pre-job estimates of fracture leakoff and stimulated reservoir volume can be derived from repeated, increasing pre-frac diagnostic fracture injection test (DFIT) volumes incorporating a hydraulic fracture simulator to derive a volume to leakoff area relationship. We can assume that a larger region of lower aperture leakoff may be beyond the tested region that may be discernable by surface deformation tiltmeter or microseismic monitoring. Thus, volumes and sizing of increasing graded particles could be derived and applied based on the area defined by pre-frac injection testing and the matchstick model derived from reservoir parameters.
In some cases, the fracture apertures cover the spectrum from centimeters to microns and cannot be discerned from near wellbore data. For these instances, a more detailed mathematical model for fractal geometry of the hydraulic fracture and the associated set of induced micro-fractures can be adopted, and the optimal injection schedule becomes one where the injected rate and the injected particle size and concentration are varied as a function of time and volume. The distinguishing feature of this optimized schedule is: the injection of larger particles with lower then higher concentrations over time; the filling of the far-field and thinner cracks first; then, the filling of larger and enlarged fractures nearer to the wellbore. In a similar manner to the first case, this type of model and optimized schedule can be developed using build-up and fall-off injectivity tests to fully characterize the fractal system.
Selected abstracts from the upcoming SPE APOGCE are presented below. Register for the conference here: http://www.spe.org/events/en/2016/conference/16apog/registration.html
Early Field Life Interference Pulse Test Design to Refine Reservoir Uncertainties: A Reservoir Surveillance Opportunity for the Wheatstone Gas Field, Australia. SPE 182325
Matthew Flett, Mathieu Muller. Chevron Australia Pty Ltd
The initial well proving and early production period of a hydrocarbon field is a valuable and unique period of field surveillance where there is the opportunity to narrow the range of uncertainty for key reservoir properties through the use of inter-well interference testing. The Wheatstone gas field, currently being developed as part of the Wheatstone liquefied natural gas (LNG) project, is located offshore north-western Australia. The start-up of the Wheatstone field, due to the nature of constrained ramp-up for LNG supply and location of development wells provides a unique opportunity for early field life interference testing. This is due to periods of individual well and well combination flows that are ideal for pulse generation and detection, with many development wells observing potential pressure responses while nearby wells are flowing. This paper will focus on the potential of initial well proving flows for pulse testing at the Wheatstone field to capture reservoir information.
Pulse testing can potentially be an important reservoir diagnostic tool, particularly during early production when the field is at initial state. Through considered test design strategy, detection of a pressure pulse in an observed well can be used to infer inter-well reservoir connectivity, connected pore volume and transmissibility. This paper provides a method to refine reservoir pore volume ranges and transmissibility. This will be accomplished through the use of dynamic model derived pulse testing type curves using homogeneous reservoir properties to match observed signals for selected active and observation well pairs within the Wheatstone field.
A suite of dynamic models exist for the Wheatstone field. These models cover a wide range of possible realisations for reservoir outcomes that affect initial static volumes and dynamic responses including structure, reservoir net to gross ratio and petrophysics (porosity, permeability and saturation). Selected dynamic models that reflect the uncertainty in inter-well connectivity, driven by variations in net to gross ratio and petrophysics, were run to develop well proving profiles for selected development wells, with non-active wells observing for a pressure pulse from this activity. Following the reservoir simulation uncertainty study of well proving flows, a homogeneous reservoir property simulation model was developed based on the reference mid case dynamic model, with constant porosity and permeability applied to active reservoir cells in the mid model. A variety of type curve pulse responses were developed for a range of porosity and permeability ranges for well pairs. These homogeneous type curves are then used to match reservoir model responses for the well proving uncertainty study, leading to estimates of potential average pore volume and permeability between well pairs. Thus the use of homogeneous reservoir model matching of interference signals during initial field conditions can be employed to appraise inter-well reservoir property ranges.
Discovering New Hydrocarbon Pay Sand Beyond The Wellbore With Reservoir Mapping While Drilling Tool – A Case Study From Offshore Sabah, Malaysia. SPE 182184
Ko Ko Kyi, Nazri Abdul Latiff, Kok Kwi Yen, Danial Saadon, M Ikhlas Rahim, Juhaidi Jaafar, Tomi Afandi and Ng Kiang Fei – PETRONAS
Tango Field, located offshore Sabah in East Malaysia, is a mature field which has been producing oil and gas for more than forty years. This field has many fault blocks, thus creating barriers to fluid and pressure communication between different fault blocks. Furthermore, the reservoir sands are turbidite sands which are difficult to correlate across the whole field. Being fan lobes, it is not easy to target these sands in drilling development wells. As part of the campaign to improve recovery and sustain production, two infill wells were drilled during 2014, by sidetracking two existing wells from the Tango-B Platform, which is located in the western part of the field. The target reservoirs are M1 and M2 sands, which still carry some upside potential based on the latest review of the field performance. To properly target and penetrate these sands in the planned wells, the Reservoir Mapping While Drilling LWD (DDEM) tool, in combination with standard triple combo LWD (Logging While Drilling) tools, was deployed. This is to ensure that the well trajectory stays within the targeted sands and the bed boundaries are detected long before the drill bit exits the sand body. Unlike previous deep reading LWD resistivity tools, the DDEM tool is a Deep Directional Electromagnetic Propagation tool which has the capability to see about 30 meters laterally beyond the wellbore. While drilling the first well, the target sands were penetrated as planned. However, there was a pleasant surprise where a new hydrocarbon sand was detected by the DDEM tool about 10 meters below the wellbore. The DDEM reservoir mapping software was used to image the newly found sand body. Based on this new finding, the drilling Bottom Hole Assembly was pulled back and the hole was side-tracked to target this new sand, which was successfully penetrated and completed. This new sand, which would not have been discovered with standard LWD tools has increased the well production by a factor of two or more. Being a turbidite sand, it was not picked up on the surface seismic section. The reservoir mapping software technology, together with the deep sensing resistivity imaging LWD tool, was instrumental in finding the new hydrocarbon sand which has substantially increased the production of Tango Field.
Application of Subsea Demulsifier Chemicals to Reduce Heavy Oil Emulsion Viscosity and Enhance Production in the Pyrenees Development. SPE 182217
M.L. Gilbert, D.A. Morley, P.A. Elliott, BHP Billiton Petroleum
The Pyrenees development consists of six low GOR, highly biodegraded oil accumulations (19-21°API) located offshore Western Australia, producing since 2010 under the operatorship of BHP Billiton Petroleum. The fields are developed by 19 horizontal production wells with reservoir sections up to 3km long. The subsea wells are tied back to a Floating Storage Production and Offtake (FPSO) vessel via subsea manifolds, flowlines and risers. As field water cuts progressed above 10%, an increasing deviation between predicted and actual flowline pressure drop was observed, indicating the formation of tubing and flowline emulsions. The additional flowing pressure loss and consequent reduction in liquid production formed the basis for a debottlenecking project to treat subsea emulsions.
Flow assurance studies had identified Pyrenees crude as possessing a strong emulsion forming tendency and therefore contingency for subsea manifold demulsifier injection was included in the basis of design. After identification of suitable demulsifier chemical through laboratory testing, chemical treatment was initially undertaken via injection at the subsea manifolds. Initial demulsifier injection into the subsea manifolds reduced flowline and riser pressure drop by up to 25%, yielding a 4% increase in field oil production.
In an attempt to realise further pressure drop reduction, the prospect of downhole injection at each well was investigated. As downhole chemical injection had been initially designed for scale inhibitor, flow assurance studies were performed to ensure repurposing the lines would not result in elevated calcite scaling risk.
Downhole chemical injection was applied across the available wells and resulted in additional 18% field oil production uplift with individual wells achieving up to 50% increase in drawdown and 58% increase in liquid production. An added benefit of downhole demulsifier injection was stabilised flow regimes and pressures observed from the downhole gauge to the topsides riser.
The minimum stable flow threshold of demulsifier concentration was empirically determined to be in the range 60-140ppm liquid, below which, the Pyrenees wells entered a demulsifier induced slug flow regime.
Downhole demulsifier was generally found to have an effective treatment on Pyrenees wells between 30% to 80% watercut.
Analysis of demulsifier effectiveness post successful downhole implementation enabled the continuous optimisation of chemical usage against changing well watercuts, to maintain strong chemical cost efficiency.
This case study provides a practical example of opportunity identification and multifaceted problem solving to significantly and safely debottleneck production. The lessons learnt in this project may be carried across to other fields and facilities to assist identifying and resolving related flow assurance bottlenecks.
Code of Practice for the Construction and Abandonment of Petroleum Wells in Queensland – As Mandatory Safety Requirements. SPE 182246
Peter Lee; Queensland Department of Natural Resources and Mines (DNRM), Mika Porter and David Maggiori (Santos).
Queensland is regarded as one of the principal regions in Australia for mineral and energy production and future investment. It produces an array of products from a world-class energy industry, which has led to the development of world class value-adding industries such as LNG production. Approximately AU$70 billion of investment in LNG processing and production with gas from the Surat and Bowen basins has been realised in the state
In November 2014 a group of 17 industry professionals from two Australian States were tasked with developing the Petroleum well Code of Practice, facilitated by APPEA. The team hailed from DNRM in Queensland and the Department of State Development (DSD) in South Australia, supported by cross industry specialists from Santos, APPEA, Origin, QGC, Senex, Beach Energy and Armour Energy. The multi-discipline team brought previous industry experience operating under various different regulatory regimes to the project, ensuring good debate and challenge throughout the development of the Petroleum COP. Given the large area of the state of Queensland and the number of basins that a set of minimum well construction standards would need to apply to, the size of the task was significant. Recognising that the industry operates in a complex environment, the aim was to set a minimum standard for all petroleum wells. The wells covered by this code are petroleum wells constructed by petroleum tenure holders on their tenures for both conventional and unconventional oil and gas exploration and production. The goal was to develop a Code of Practice that addressed the petroleum well life cycle phases.
The principle of this new Code was to support an objective based regulatory regime rather than prescriptive requirements, and address the following main considerations, over and above the requirements set out in the existing CSG Code of Practice:
The contents of the Petroleum COP fall into the following categories and ensure that adherence to the Petroleum COP protects an individual company’s licence to operate:
Ultimately, the benefits of collaborative development of a code will result in improved protection of groundwater resources in the state, acceptance by communities as an acceptable, transparent construction standard, and result in improved social licence for petroleum operations. In addition, a collaboratively developed code will result in consistency between CSG and other petroleum construction standards. Many CSG companies have other petroleum tenures, and the code will facilitate the ability for petroleum tenure holders to efficiently construct water bores and convert wells to water bores if required.
Selected abstracts from the upcoming SPE APOGCE are presented here below. Register for the conference here: http://www.spe.org/events/en/2016/conference/16apog/registration.html
Managing Abandonment in Australia SPE-182416
P. Askew, C. Bourdeau, A. Volkenborn, A. Lea-Cox, A. Charan, Accenture Strategy
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. 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.
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. E&P operators are expected to spend between USD 2 to 3 billion in decommissioning costs and overruns. From a ‘risk of unknowns’ perspective, there is a residual risk of unknown liability in the event of bankruptcies/walkouts. Such circumstances could leave the Government to pick up entire costs of major restorations or excessive project overruns by operators.
E&P Operators can execute quick wins through rig optimisation, contracting and procurement, effectuating >10% reduction in expenditure. Building internal capabilities by standardisation, lean execution best practices, a mature asset strategy and systematic cost estimation methodology could contribute another 20% to cost reduction. Establishing new business models by aggregating industry demand, outsourcing to specialist/salvage companies, technology investments or sharing resources with other operators could contribute another 20% to cost reduction. Any government action such as reducing the number of regulatory bodies for efficient decision making could further reduce costs. To sum it up, operators could optimise impact of decommissioning by anywhere between 10% and 50%.
Government actions could include incentivising operators to further optimise decommissioning costs, maximising mature asset extraction to increase tax revenue and promoting reuse of assets/facilities. Government and companies will require a legal or commercial workaround to incentivise mature field and decommissioning operators (e.g. acquiring a legal entity, incumbents retaining a stake or adjusting the tax rules).
All stakeholders will need their own strategies but without collaboration at multiple levels, new solutions to technical, people and regulatory issues, they will bear increased costs, liabilities and leave behind a sub-optimal situation for years to come.
Justifying Appraisal in a Low Oil Price Environment: A Probabilistic Workflow for Development Planning and Value of Information. SPE 182410
Stuart Walters, Gavin Ward, Bruce Wigston and Shyam Talluri, Chevron Australia Pty Ltd
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 that 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.
Subsea Multiphase Flowmeter: Performance Tests in Multiphase Flow Loop. SPE-182378
Ö. Haldun Ünalmis, Vishal V. Raul, Vijay Ramakrishnan, Weatherford
Performance of a new three-phase (3-P) flow measurement system is presented using multiphase flow loop data. The system consists of two currently available products: an optics-based flowmeter and an infrared-absorption-based water-cut meter. This approach of combining two robust and field-proven technologies to determine the measurement capability and performance of the combined system under realistic flow conditions is demonstrated for the first time. The new 3-P flow measurement system represents a viable alternative for subsea multiphase flow measurement and can also be used on offshore platforms and onshore multizone applications.
The flowmeter system relies on three main measurements: bulk velocity and sound speed measured by the optics-based flowmeter, and water-cut measured by the water-cut meter. The velocity measurement is a robust measurement based on turbulent flow and is not affected by upstream flow conditions. The water-cut measurement is based on near-infrared absorption of water and oil molecules, and therefore, is immune to water salinity and the presence of gas (such as free gas, gas in solution, and oil foaming). Total flow rate is calculated using the bulk velocity measurement; the liquid holdup and density of the mixture are obtained by introducing the mixture sound speed and the water-cut measurements into a flow model.
The results of the multiphase flow loop test demonstrated that the new flow measurement system is capable of resolving total volumetric flow rates as well as phase volumetric flow rates in a broad gas-volume-fraction (GVF) band. Furthermore, mixture density can be successfully calculated from the flow model and, as a result, the mass flow rates can also be determined. The test data also confirm that the water-cut measurement is not affected by foaming issues and associated density variations. The test results are discussed in detail in the paper.
The new flow measurement system offers several advantages. The optics-based flowmeter that goes into the well provides flow measurement for the life of the well with no significant drift in signal. The flowmeter can be installed in any orientation and does not require recalibration. Its nonintrusive and fullbore features mean no permanent pressure loss, and high resilience to erosion and corrosion. The nonnuclear water-cut meter measures water cut in the broad GVF spectrum and is not affected by challenging flow conditions, such as slug flow.
A Case Study for Deriving and Calibrating Net Reservoir in Thinly Bedded Siliciclastic Formations: Brigadier Formation, Offshore Australia. SPE 182361
Paul Pillai, ISOS Petroleum, Brian Douglas, Chevron Australia, Hendrayadi Prabawa, Schlumberger
The Brigadier Formation is a thinly bedded reservoir that contains approximately 40% of in-place gas resource in Wheatstone field, which underpins the 2-train Wheatstone Liquified Natural Gas (LNG) project in Western Australia. The development drilling campaign has recently been completed with three Wheatstone development wells targeting the Brigadier formation in the northern part of the field. Accurate and timely determination of net reservoir thickness is crucial not only for evaluating field volumetrics and performance, but also to support time- sensitive drilling decisions. In the case of two of the Brigadier wells, the decision to accept a development well location or move to a contingent well location was required within 72 hours of penetrating the reservoir with a pilot hole. Additionally, TD (total depth) decisions in the Brigadier Formation were made on the basis of real time kH (cumulative permeability thickness) evaluation from Logging-While-Drilling (LWD) logs and are essential for balancing well deliverability requirements with minimising risk of early water breakthrough by optimising standoff from the aquifer.
A fit-for-purpose approach to calibrate and evaluate net reservoir in the thinly bedded Brigadier Formation will be discussed. Several methods of net reservoir determination have been tested in the Wheatstone field. Standard resolution methods like density-neutron cross-over, and photoelectric factor, and high resolution methods like electrical image logs (water-based Formation Micro-Imager (FMI) and oil-based New Generation Imager (NGI)) and LWD alpha processed density are compared against core-based sand counts to derive the most reliable and fit-for-purpose method of net reservoir determination. Mud-type, conveyance methods and borehole condition also impacts the results of net reservoir evaluation.
The results from a combined density-neutron-photo electric factor method was found to compare very well to core net reservoir and image log-derived net reservoir, across mud types, reservoir fluids and hole angles. It is locally calibrated and blind-tested successfully across different wells. The nuclear tools are logged in every well in the field so this method of calculating net reservoir could be applied consistently across all wells. An added advantage is that the evaluation of net reservoir is independent of porosity and hence, net reservoir will not need to change with different generations of petrophysical evaluation.
The SPE YP committee is proud to present the SPE APOGCE Young Professionals Workshop on the first day of SPE APOGCE 2016, Tuesday 25th October. This event is proudly sponsored by BHPBilliton.
APOGCE Conference Opening
• Gerry Flaherty, Janeen Judah, Hon. Bill Marmion MLA
• Keynote from Peter Coleman, CEO & Managing Director, Woodside Energy Ltd
• Executive Plenary Session
•Facilitated by Gerry Flaherty &Michael Scott, Chevron Australia
•Nigel Hearne, Managing Director, Chevron Australia
•TetsuroTochikawa, EO & VP Technical, Inpex
•DzafriSham Ahmad, VP LNG, Petronas
•Rod Duke, VP Downstream GLNG, Santos Ltd
•Aparna Raman, Managing Director, Schlumberger Australia
•Mike Utsler, COO, Woodside Energy Ltd
•Bullshift –”How to get more honesty and straight talk at work”
•Facilitated by Andrew Horabin
A communications workshop which will give participants practical tools to shift the bull at work
• YP Executive Panel Session –If you could go back, what advice would you give?
This session will bring together industry leaders to share their experience and advice with workshop participants on the dynamic nature of the industry, why it’s here to stay and why we’re poised to catch the next wave of opportunities
• Brett Darley, CEO & Managing Director, Quadrant Energy Ltd
• Mike Utsler, COO, Woodside Energy Ltd
• Justin Nash, GM North West Shelf, BP Developments Australia Pty Ltd
• Janeen Judah, 2017 SPE President, Chevron Corporation
Q&A and discussion facilitated by:
• Rebecca Lewis, Divisional Adviser –Operations, Woodside Energy Ltd
Unwind by joining the main conference networking session to close out the day.
Full Event Flyer is available here:
Registration is via APOGCE registration page: http://www.spe.org/events/en/2016/conference/16apog/registration.html
SPE Members: $120
Date: Wednesday, 26th October 2016
Where Astral One, Crown Casino, Perth
Dress: Business / Semi-Formal
Time 7:00 pm drinks for 7:30 pm start
Enjoy Australian influenced cuisine whilst socialising with SPE APOGCE 2016 delegates and local SPE members at the feature social function for the 2016 APOGCE.
This dinner will be an experience not to be missed that has incorporated Western’s Australia’s relaxed atmosphere into the evening. Come along and indulge in top-notch food stations, delicious beverages, and a great atmosphere to mingle.
With MC Russell Woolf leading the evening – whether you book a single ticket or table, this event will impress!
SPE Member: $160
Non Member: $200
Package of 10: $1600
Tickets to this exclusive event are limited and available here
Contact: Raymond Klein Raymond.Klein@quadrantenergy.com.au
The Western Australian SPE section recently held its Annual General Meeting (AGM) on Thursday 14th July, 2016. This meeting was held in conjunction with the regular monthly Technical Luncheon Seminars hosted by the section.
During the AGM, Stephanie Lim (Total E&P, 2015-2016 SPE WA Section Chair) provided a summary of the 2015-2016 WA chapter performance to 65 local attendees. Stephanie highlighted the section’s success and awarded scholarships to student recipients from WA. Over the last financial year, SPE WA held 27 technical presentations, a golf day, fund-raising ball, gala dinner and various other networking initiatives. Stephanie also thanked the sponsor companies who assisted SPE WA.
The following representatives were elected for the 2016-2017 Executive Committee:
Afterwards, Daniel shared a preview of the year ahead for the chapter and promoted the upcoming APOGCE conference in Perth, October 2016.
The slides shared during the AGM are available here.
Following the AGM, Chris Fair (Oilfield Data Services Inc.) provided a technical presentation on the topic of “Using Automated Reservoir and Production Engineering Tools to Make Quicker Decisions.” Chris explained how the automation of production data cataloguing can save time for engineers, allowing a bigger focus on the fundamental analysis and interpretation of data. Slides from Chris’ lecture.
Please find more information on SPE WA’s events at our local chapter website: http://www.spe-wa.org/