Rizzato, Paolo (Eni S.p.A.) | Castano, Daniele (Eni S.p.A.) | Moghadasi, Leili (Eni S.p.A.) | Renna, Dario (Eni S.p.A.) | Pisicchio, Patrizia (Eni S.p.A.) | Bartosek, Martin (Eni S.p.A.) | Suhardiman, Yohan (Eni Australia Ltd.) | Maxwell, Andrew (Eni Australia Ltd.)
This paper describes the results of an integrated reservoir study aimed at producing hydrocarbons through a sustainable development from a green High Temperature (HT) giant CO2-rich gas field in the Australian offshore. The development concept addressed the complex challenge of exploiting resources while minimizing the carbon impact.
In order to characterize the reservoir in the most detailed way and to describe the fluids behaviour, a 1.8 million active cells compositional model has been built. An analytical aquifer has been coupled in order to represent the boundary conditions of the area.
The faults system, interpreted on seismic data by geophysicists, has been included in the simulation model. The selected development plan includes the re-injection of the produced CO2 into the aquifer of the reservoir itself. The supercritical CO2-brine relative permeability curves at reservoir conditions have been provided by Eni laboratories, where the experiments were performed.
Therefore, a detailed model has been built with the purpose of: Defining producing well and CO2 injector well locations, numbers and phasing to evaluate expected CO2 injectivity and CO2 breakthrough issues; Optimizing the development concept through a risk analysis approach; Estimating the CO2-rich gas injectivity and storage capacity in the saline aquifer of the reservoir; Predicting the behavior of the CO2-rich gas after re-injection (breakthrough timing and plume migration); Maximizing the CO2 sequestration in the reservoir.
Defining producing well and CO2 injector well locations, numbers and phasing to evaluate expected CO2 injectivity and CO2 breakthrough issues;
Optimizing the development concept through a risk analysis approach;
Estimating the CO2-rich gas injectivity and storage capacity in the saline aquifer of the reservoir;
Predicting the behavior of the CO2-rich gas after re-injection (breakthrough timing and plume migration);
Maximizing the CO2 sequestration in the reservoir.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Copyright 2019 held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors. ABSTRACT Today, many machine learning techniques are regularly employed in petrophysical modelling such as cluster analysis, neural networks, fuzzy logic, self-organising maps, genetic algorithm, principal component analysis etc. While each of these methods has its strengths and weaknesses, one of the challenges to most of the existing techniques is how to best handle the variety of dynamic ranges present in petrophysical input data. Mixing input data with logarithmic variation (such as resistivity) and linear variation (such as gamma ray) while effectively balancing the weight of each variable can be particularly difficult to manage. DTA is conceived based on extensive research conducted in the field of CFD (Computational Fluid Dynamics). This paper is focused on the application of DTA to petrophysics and its fundamental distinction from various other statistical methods adopted in the industry. Case studies are shown, predicting porosity and permeability for a variety of scenarios using the DTA method and other techniques. The results from the various methods are compared, and the robustness of DTA is illustrated. The example datasets are drawn from public databases within the Norwegian and Dutch sectors of the North Sea, and Western Australia, some of which have a rich set of input data including logs, core, and reservoir characterisation from which to build a model, while others have relatively sparse data available allowing for an analysis of the effectiveness of the method when both rich and poor training data are available. The paper concludes with recommendations on the best way to use DTA in real-time to predict porosity and permeability. INTRODUCTION The seismic shift in the data analytics landscape after the Macondo disaster has produced intensive focus on the accuracy and precision of prediction of pore pressure and petrophysical parameters.
Consoli, C. (Geoscience Australia, now at Global CCS Institute) | Nguyen, V. (Geoscience Australia) | Higgins, K. (Geoscience Australia) | Khider, K. (Geoscience Australia) | Lescinsky, D. (Geoscience Australia) | Morris, R. (Geoscience Australia)
Several offshore sedimentary basins around Australia have been assessed as potentially prospective for CO2 geological storage. A recently completed detailed assessment of one of these basins, the Bonaparte Basin, offshore northern Australia, indicates that the Mesozoic-aged deep saline formations forming the Petrel Sub-basin, a major structure element of the Bonaparte Basin, are highly prospective for CO2 geological storage, and represent suitable depocentres for regional emissions.
Petrophysical, seismic and facies analysis shows that the deep saline formations comprise multiple high quality reservoir-seal pairs. A basin-scale geological model indicates that migration-assisted storage (MAS) is the primary trapping mechanism due to long migration pathways (up to 70 km) with no major structural traps. Plume-scale, dynamic injection simulations show high potential injection rates of over 10 million tonnes supercritical CO2 per annum. After 1000 years, the model predicts maximum plume migration of 30 km from the simulated injection wells. A CO2 storage resource potential of over 15,000 million tonnes was estimated for the reservoirs over the entire Petrel Sub-basin using a methodology suitable for MAS plays.
The highly suitable reservoirs are located less than 300 km from major local CO2 emission sources. This study shows that the Bonaparte Basin in northern Australia is potentially a highly prospective location for carbon capture and storage projects in Australia, and possibly for the broader region.
Giumelli, Martin (Eni Australia) | O'Shea, Paul (Eni Australia) | Australia, Eni (Smith Bits, a Schlumberger Company) | Maliardi, Alberto (Eni S.p.A.) | Sosnowski, Paul (Smith Bits, A Schlumberger Co.) | Shepherd, Aaron (Smith Bits, A Schlumberger Co.) | Sadawarte, Sagar Sudhakar (Smith Bits, A Schlumberger Co.) | Scordella, Maurizio (Smith Bits, a Schlumberger Company) | Bits, Smith (Smith Bits, a Schlumberger Company)
Exploration offshore Australia requires the operator to drill an 8½” vertical borehole through the difficult Plover sandstone. The highly abrasive formation, with UCS between 15-30kpsi, has been problematic causing extremely short PDC bit runs and low ROP. Erratic torque response was causing a reduction in BHA performance and system reliability.
To solve the problems, a new system was devised that enables a PDC cutter to fully rotate while drilling to increase cutting efficiency/bit durability while reducing frictional heat.
To strategically position the rolling cutters to obtain maximum benefit, a forensic analysis was performed on PDCs used in offsets. After investigation, engineers identified accelerated wear flats in the shoulder area and a new PDC design was implemented by positioning two 13mm RCs in the shoulder area on each of the eight-blades. The target objectives would be to drill the 8½” hole section through Plover with one PDC bit and improve ROP.
The first well required one conventional PDC and one RC-PDC to drill through the Plover to TD. The standard PDC (10blades/16mm) drilled 90m (3739-3829m) at an average ROP of 5.4m/hr. The bit was pulled for low ROP and graded 8-3-CR-C-X-IN-BT-PR. The RC-PDC (813) drilled 126m (3829-3955m) at a ROP of 4.3m/hr. The RC-bit was in
good dull condition (1-2-CT-S-X-IN-PN-TD).
Parameter/bit adjustments in the second well enabled an RC-PDC to drill the entire Plover interval (3283m-3425m) in one run at an ROP of 9.26m/hr. The RC-PDC run was 286% faster than a direct offset that required four standard PDC bits to TD the section at an average ROP of 2.4m/hr.
The RC-PDC torque response was smooth compared to erratic torque response of standard PDC in Plover. The increased meterage and ROP saved the operator over $1millionUSD.
Copyright 2013, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 26-28 March 2013. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC.
The first hydraulically operated completion was installed in Australia in 2004 (Guatelli et al 2004). Since then, a number of intelligent completions have been installed in offshore Australia. The remoteness of offshore Australia, particularly in the Timor Sea area, means intervention vessels are not readily available and well interventions are costly operations. For this reason, intelligent completion is considered to be an attractive alternative, by providing a down-hole solution to actively manage the reservoir production life and delay potential water breakthrough.
The Kitan oil field is remotely located in the Joint Petroleum Development Area (JPDA) between East Timor and Australia. The Kitan oil field production facilities consist of three vertical producing wells, subsea flowlines, risers, and one Floating Production Storage and Offloading (FPSO) facility. The wells were completed with an intelligent design and cleaned up using a rig before the FPSO arrived on location.
The intelligent completion design consists of two multi-stage hydraulic down-hole Flow Control Valves (FCVs) and three Down-Hole Gauges (DHGs) to independently control and monitor two different production zones. The FCVs have a total of 8 positions (fully opened, fully closed and 6 intermediate choke positions).
It is planned to close the lower FCV to shut off water production from the lower zone while the upper FCV remains fully opened over the field life. The different FCV choke positions were utilized during the field startup and during the early stages of production while the water cut was still low, to overcome unforeseen technical limitations in the production system, and to optimize hydrocarbon production.
This paper describes various aspects of the Kitan oil field intelligent well completion from design through installation and field startup to early stage of production operations, and includes technical problems encountered during the field startup as well as lessons learnt.
Bulk-phase CO2 injection into saline aquifers can provide substantive reduction in CO2 emissions if the risk arising from aquifer pressurization is addressed adequately through mechanisms such as brine production out of the system (Anchliya 2009). While this approach addresses the risks associated with aquifer pressurization it does not address the problem of ensuring CO2 trapping as an immobile phase and its accumulation at the top of the aquifer. The performance of bulk-CO2-injection schemes highly depends on the seal-integrity assessment and presence of thief zones. The accumulated pocket of free CO2 can readily leak through a breach in the aquifer seal. Ideally, the aquifer should be monitored as long as the free CO2 is present, but if the CO2 is not immobilized, it is expected to remain underneath the seal rock for more than 1,000 years. Therefore, long-term monitoring of the seal integrity and avoiding leakage will be very costly.
To minimize the free CO2 below the caprock, we propose an engineered system to reduce aquifer pressurization and accelerate CO2 dissolution and trapping. We achieve these objectives through effective placement of brine injection and production wells to facilitate the lateral movement (hence, residual and solubility trapping) of CO2 in the aquifer and impede its upward movement. The simulation results for example engineered well configurations in this paper suggest that substantial improvements in immobilizing CO2 can be achieved through increasing enhanced solubility and residual trapping that result from better CO2-injection sweep efficiency. This approach has the potential to greatly reduce the risk of CO2 leakage both during and after injection. The controlled injection of CO2 with this technique reduces the uncertainty about the long-term fate of the injected CO2, prevents CO2 from migrating toward potential outlets or sensitive areas, and increases the volume of CO2 that can be stored in a closed aquifer volume during the CO2-injection period. Field-scale compositional simulation cases are discussed, and sensitivity studies are used to provide guidelines for well spacing and flow rates depending on aquifer properties and the volume of CO2 to be stored. Although it requires additional drilled wells, the active engineered configuration proposed for CO2 injection significantly reduces the reservoir volume required to effectively sequester a given volume of CO2, and the increase in the cost caused by additional wells is recovered by dramatic reduction in monitoring cost.