Understanding the integrated performance of complex artificially lifted wells on not normally manned (NNM), offshore platforms without invasive techniques represents a challenge not only to minimizing operating costs but also to optimizing production and thereby maximizing value. Often the analysis of such problems is hindered by the complex interactions between identified production constraints and by a lack of operating data.
The Cliff Head oil field (offshore Western Australia) is developed with an innovative coiled-tubing deployed-electrical-submersible-pump (CT-ESP) artificial-lift system. This paper describes the process by which ESP and well data, in conjunction with a well-performance-modeling software, have been used as a powerful tool to diagnose well-performance issues and optimize production. Production trends were created on the basis of real-time production data to understand ESP performance. Individual-well models were created to identify potential causes of declining performance--in this case, the use of an ESP performance-limiting factor (PLF) indicating deteriorating ESP performance because of solids buildup.
On the basis of the model results, chemical soaks were implemented on two production wells to remove flow restrictions within and around the ESPs. The treatments increased the oil-production rates by 17 to 48%.
Following a debottlenecking study, reservoir simulation in combination with detailed ESP-performance analysis concluded that total-field-production improvements of up to 50% were possible. Consequently, the next phase of field development will install larger-capacity ESPs.
This paper outlines how field data and desktop tools were combined successfully to monitor and diagnose well-performance issues to deliver material production enhancements.
Probabilistic methods for reserves estimation, including uncertainty quantification and probabilistic aggregation, have gained widespread acceptance in the oil and gas industry, since the first comprehensive guidelines were issued by the Society of Petroleum Engineers (SPE) in 2001. The probabilistic methods now used in the oil industry, as proposed in these guidelines, are similar to those also used in portfolio theory and risk management by the finance industry. A significant amount can be learned from the extensive experience with probabilistic methods and quantification of risk with measures [e.g., value-at-risk (VAR)] in financial risk management. Especially, the guidelines issued by the Basel II Accord (Bank for International Settlements 2006) and the discussions since the 2008 financial crisis contain important lessons.
In this paper, we examine a fundamental question: "Is the P90 reserves value an appropriate measure for quantifying the reserves' downside?" For the P90 reserves value to be considered a good measure of the reserves' downside, it needs to possess a number of basic characteristics involving P90 reserves for each field and the probabilistically aggregated P90 reserves for the portfolio of fields. Analogous to the definition of a coherent risk measure used in the finance industry, we define these characteristics for P90 reserves.
The P90 reserves are as good a risk measure as VAR used in the financial industry. However, like VAR, it is not a coherent risk measure. A possible uncertainty scenario, in which one of these necessary characteristics does not hold, is given. An alternative measure of risk for quantifying the reserves' downside, defined as the average reserves over the confidence interval higher than P90, is presented. This is a coherent risk measure.
In this paper, we highlight the appropriateness and limitations of using the P90 reserves estimate as a measure of the reserves' downside. Understanding of the limitations posed by using the P90 reserves value is vital in management of reserves risk.
The rise in global energy demand is pushing major resource holders to urgently develop and monetise their hydrocarbon reserves in the context of evermore challenging scenarios. This paper will describe how this can be done in a way that optimises recovery and creates most value.
It will highlight how, as we extend these physical and commercial frontiers, it is increasingly important to marry new thinking that builds on, and integrates in new ways, established technologies and expertise with a strong culture of 'best in class' project delivery. This is all in pursuit of concepts, technologies and techniques that lead to lower development and operating costs in a safe and socially responsible manner.
To illustrate how innovative technology, engineering, commercial acumen, and partnerships unlock value from gas plays, the paper will focus primarily on Floating LNG (FLNG) but will also touch on key elements of a Gas to Liquids (GTL) project to reinforce the argument.
Monetising gas from fields far offshore whilst removing the need for long-distance pipelines and extensive onshore infrastructure is an attractive proposition in theory, but presents immense practical challenges. Potential solutions will be discussed in the context of Shell's FLNG concept for the Prelude gas field offshore Australia. The speaker will highlight how material gains would be expected to accrue in the design and construction phases of the FLNG solution, thanks to the repeatability.
On the GTL front, the paper will briefly discuss how this solution unlocks the opportunity to arbitrage between the oil price and that of natural gas, creating increased commercial viability of gas molecules. The focus of this section of the presentation will be on the necessary alignment in innovative solutions and world class project delivery performance required to create value through this channel.
To conclude, the paper will re-emphasise how innovation and technology, underpinned by world-class project execution, are essential in creating development optionality and thus unlocking optimal monetisation of the resources.
The feasibility of carbon dioxide (CO2) injection into an extensive aquifer in the North Sea is assessed. The impact of seal permeability, horizontal permeability, perforation interval, number of wells, aquifer size and cap rock size on the effectiveness of large-scale storage is assessed. A compositional numerical simulation is performed in the period of 50 years (30 years of injection and 20 years post-injection). We study volumes equivalent to the emissions of a large power station in the UK, 10 Mtonnes/year and find the necessary aquifer dimensions, cap rock size and horizontal permeability to allow safe storage assuming that the pressure increases by no more than 10%.
We find no impact of the number of wells on field-average pressure response as long as the total injection rate remains constant. However, using more wells enables CO2 to be trapped by immobilization and dissolution while giving poor sweep efficiency. In order to achieve the target injection rate with 5 injectors, two appropriate aquifer dimensions are proposed: an area of 3,850 km2 with thickness of 1,260 m; and an area of 11,550 km2 with thickness of 630 m. For the same aquifer volume, thickness plays a more important role on pressure response than area. Only deeper layers of the aquifer should be perforated in order to minimize pressure build-up and enhance CO2 displacement efficiency.
CO2 emissions contribute towards the greenhouse effect and climate change (Ghanbari et al., 2006). The majority of anthropogenic CO2 comes from power and industry sectors, for example, fossil fuel combustion (IPCC, 2005). Carbon Capture and Storage or CCS has generated considerable interest because it is a way of reducing these emissions (Holloway et al., 2006). Various geological sites are considered suitable for storage in CCS, including depleted oil and gas reservoirs, deep saline aquifers and deep unminable coal seams (Gale, 2004). In the past, the main interest of CO2 injection relied on oil or gas reservoirs as an enhanced oil recovery (EOR) technique where CO2 and the remaining oil in place become miscible and the oil can therefore be extracted from the reservoir. However, saline aquifers are currently considered as potential sequestration sites since they have a large estimated capacity and wide distribution throughout the globe (Gale, 2004, Nicot, 2008). Saline aquifer sequestration was first mentioned in 1992 (Van der Meer, 1992) and currently, there are several successful projects of aquifer
injection, for example, Sleipner (Norway), In Salah (Algeria), Ketzin (Germany), and K12B (Netherlands) which prove the feasibility of this emerging storage option. However, saline aquifer storage may cause several problems including migration into groundwater leading to contamination (Gale, 2004) and risk of overpressure, causing fracturing and possible leakage due to its shallow position. Pressure build-up is also one of the associated risks for aquifer storage, as large amounts of fluid are added. This could eventually induce fracturing or aquifer deformation which negatively impacts storage security.
Offshore Asia Pacific - No abstract available.
This paper summarises original development work implemented by Ocean Resource into a new type of Unmanned Production Buoy facility, the Sea Producer. This work, which is both comprehensive and wide-ranging, covers the use of autonomous buoy technology to develop various offshore oil and gas production scenarios which would otherwise be uneconomic or indeed impossible. Recently this technology has received considerable interest as it represents, for some smaller developments, possibly the only sensible and economic way forward.
Ocean Resource has developed and pioneered the concept over a period of 20 years and is the only company with specific experience and expertise in this complex area. Ocean has operated and maintained its own high stability buoy systems and has completed a number of buoy designs for working buoy systems in use with Apache, Mossgas Pty, Exxon-Mobil and others for oil related operations. More recently Ocean Resource has been responsible for the design of a 5MW Power Buoy for CNR International UK Ltd (Canadian Natural Resources). Unfortunately Monitor Oil PLC, the principle constructor, went into liquidation prior to completion of the project but it is envisaged that this unit, which is 95% complete will shortly be redeployed on another field. The Power Buoy located at Dundee is subject to an option agreement for the purpose.
Ocean Resource's low cost autonomous buoy systems represent a game-changing technology that will enable the economic development of hitherto unexploitable or stranded oil and gas reserves. The technology is generally branded as Sea Commander where it relates to field control buoys (a developed product) and Sea Producer where it relates to production.
Sea Producer enables a step-change in offshore development expenditure lowering capital costs at the start of project together with greatly reduced operational costs leading to low "through-life?? costs for standalone, step-out developments or early production scenarios. Furthermore the relatively minimal nature of the offshore facilities comprising the buoy and storage system leads to rapid deployment and hence faster income and profit return to any offshore project.
The unique autonomous buoy technology has been developed by Ocean Resource over a period of 20 years and is an evolution of existing systems. It is therefore both mature and proven. It can be used for sub-sea oil and gas field control, remote pigging, multi-phase pumping, chemical injection, subsea production support and remote flaring.
Prelude FLNG project - No abstract available.
Nikolinakou, M.A. (Bureau of Economic Geology, The University of Texas at Austin) | Luo, G. (Bureau of Economic Geology, The University of Texas) | Hudec, M.R. (Bureau of Economic Geology, The University of Texas) | Flemings, P.B. (Bureau of Economic Geology, The University of Texas at Austin)
We use elastoplastic geomechanical models (Modified Cam Clay) to predict how stresses and pore pressures evolve in mudstones bounding a salt body. We show that the loading caused by visco-elastic salt relaxation processes can induce pore pressure perturbations that extend kilometers away into the sediments. The time scale of dissipation of these perturbations is on the order of millions of years, suggesting that pore-pressure anomalies should commonly be present in sediments near salt systems. Because previous models have not coupled changes in the stress field to changes in the pore-pressure field, they are unable to predict the interdependence between pore pressure and stress. However, this interdependence is critical to well-bore design, as the range of safe drilling pressures is defined between the values of the minimum principal stress and the wall-rock pore pressure (safe-mud window). Our coupled poro-elastoplastic models show that underpressures can lead to sudden pressures drops under the salt, while excess pore pressures close to the flank can shift the safe-mud window to higher values. These results may provide insight into pressure perturbations that have been observed in deepwater drilling near salt. Coupled geomechanical models such as the ones presented here can offer more reliable predictions of stresses and pore pressures in salt systems around the world.
The reliable prediction of pore pressures around a drilling well is critical for the stability of a wellbore. The ability to anticipate and plan for sudden changes in the fluid pressures can not only spare millions of dollars, but also prevent the loss of human lives and environmental pollution. Drilling problems are often reported adjacent to, or beneath salt bodies, leading to additional expense or even abandonment [1-5]. This is an important concern for the drilling industry, considering that a significant number of hydrocarbon reservoirs around the world are found below salt bodies [6, 7]. From a geomechanical point of view, non-geostatic stresses and non-hydrostatic pore pressures are expected around salt structures. Salt is a viscous material that cannot sustain deviatoric stresses. Under differential loading it flows and changes shape, and eventually relaxes to an isostatic state. The emplacement of a salt body may cause significant deformation of the surrounding sediments, perturb their state of stress and create local overpressures. The objective is, hence, to estimate the stress changes within the sediments that result from the emplacement and relaxation of the salt. Because wall-rocks are porous materials, stresses are coupled to pore pressures, according to the effective stress principle  and the theory of pressure dissipation . Coupled mathematical models have been used extensively in geotechnical practice [10, 11] and other poromechanical fields , however they have seen restricted application in the hydrocarbon industry because they are computationally intensive, and they require more specialized laboratory testing programs for the model input parameters. In some cases, the presence of pore pressures is modeled by considering a porepressure profile [28-30]; however, pore pressures are assumed constant (usually hydrostatic) and are not updated to reflect perturbations caused by the solid mechanical model.
Wang, Yingying (Offshore Oil/Gas Research Center, China University of Petroleum) | Duan, Menglan (Offshore Oil/Gas Research Center, China University of Petroleum) | Wang, Deguo (Offshore Oil/Gas Research Center, China University of Petroleum) | Liu, Junpeng (Offshore Oil/Gas Research Center, China University of Petroleum) | Dong, Yanhui (Offshore Oil/Gas Research Center, China University of Petroleum)
Two wells have been designed and completed using a combination of monitoring, isolation and injection control equipment to provide an understanding of injection behavior in extended-reach laterals and possible matrix bypass events (MBE) in the Nikaitchug field in Northern Alaska. These lower completion designs also provided a means to evenly distribute injection along the length of the lateral section as well as a means of mitigation and control of water if necessary.
In order to facilitate direct injection, a specifically formulated breaker system was developed to provide a delay to allow spotting in the openhole horizontal prior to running the liner and lower completion injection control assemblies. The ability to place the breaker system after drilling the horizontal mitigated risk associated with temporary flowback when inflow control devices were installed. Both post intervention and flow back were not desired.
The breaker system was formulated to provide a delay and allow the liner and injection control assembly to be installed before degradation of the residual filtercake caused uncontrollable losses thus allowing the completion phase to proceed as planned. The filtercake was deposited by a reversible invert reservoir drill-in fluid system used to drill the horizontal sections. The breaker system was unique in that it was blended as an invert emulsion and consisting of an oil continuous phase and an aqueous discontinuous phase that included a glycol acid precursor. An oil-based system was desired to reduce friction thus facilitating the installation of the lower completion hardware for these extended-reach wells.
This paper discusses the upfront assessment process, the reversible invert drill-in fluid system, the chemistry and subsequent optimization of the breaker system to achieve the drilling and completion objectives. In addition, the actual field results and lessons learned will be discussed.