Decommissioning involves the safe plugging of the hole in the earth's surface and disposal of the equipment used in offshore oil production. Decommissioning is a rapidly developing market sector in the petroleum business, with major potential and major risks. It is a source of major liability for counties, operators, contractors and the public and it must be understood if it is to be managed cost effectively. Offshore decommissioning involves 10 steps: project management, engineering, and planning; permitting and regulatory compliance; platform preparation; well plugging and abandonment; conductor removal; mobilization and demobilization of derrick barges; platform removal; pipeline and power cable decommissioning; materials disposal; and site clearance. Each step is discussed below.
Water management can significantly add to the cost and environmental footprint of oil production and innovations in water management can provide significant economic and environmental gains. New treatment technologies make recycling of hydraulic fracturing water possible. Methods for recycling fracking water include anaerobic and aerobic biologic treatment; clarification; filtration; electrocoagulation; blending (directly diluting wastewater with freshwater); and evaporation. Generally, anaerobic treatments on wastewater are implemented on concentrated wastewater. Anaerobic sludge contains a variety of microorganisms that cooperate to convert organic material to biogas via hydrolysis and acidification.
OnePetro is an online library of technical literature for the oil and gas exploration and production (E&P) industry. OnePetro is one of the most comprehensive resources available on upstream oil and gas. Adding OnePetro articles to PetroWiki will assist industry professionals in finding relevant answers to technical questions. The East Spar Development - Novel Subsea Production System Allow Optimum, Low Cost Development of this Remote Field Australia and Control Buoy Offshore Western.
A development programme offshore Western Australia required near horizontal 8.1/2" wellbores to be drilled through challenging formations. The hole section intersected sand-shale interlayers, referred to as the Tiger Sands, which is an abrasive formation with unconfined compressive strength (UCS)between 15,000psi and 20,000psi, with maximum UCS recorded up to 30,000psi. Underlying the Tiger Sands is the well cemented, abrasive Brewster sandstone with average UCS of 15,000psi and maximum UCS recorded up to 21,000psi, which has demonstrated a propensity to natural fractures. These challenges resulted in poor bit durability, low rate of penetration (ROP), difficult directional control,excessive shocks and downhole vibrations and significant downhole mud losses. The complexity of the drilling conditions required a systematic approach to be employed to optimise the poly-diamond crystalline (PDC) drill bit solution in order to improve durability and optimise ROP while successfully managing directional control, losses and ultimate drilling cost through the interval.
In addition to drill log analysis, after operations reviews (AORs) provided a comprehensive summary of operations from a rig perspective. These summaries were then used by the onshore engineering team to work in collaboration with the service sompany engineering team to develop a bit optimisation strategy. The first development well of the campaign was drilled with a standard 8 bladed 13mm PDC bit.
Natural fractures were penetrated and a total of ~4,500bbl of synthetic sased sud (SBM) was lost to the formation. The bit suffered impact damage and, therefore, had reduced durability. To solve thisproblem, a systematic approach was followed to gradually introduce improved design elements. Bit design progressed from cutter design, improved technology and ultimately, the introduction of new PDC cutter technology to record the fastest on bottom ROP for the drilling campaign of 10.32m/hr. Improved ROP and optimisation of the loss treatment strategy, allowed drilling operations to continue with minimal exposure to losses when present. Positive AOR feedback and continuous development from the service company resulted in further improvements to the PDC bit design with the introduction of ridged diamond elements and the latest generation conical elements to further improve steerability and ROP.
Continued developments resulted in New Design 4 being run in well 10. The entire interval was drilled in one run with excellent steerability and an overall 159% improvement in ROP equating to a reduction in drilling time by 5 days going from the original 813 PDC to the final New Design 4. In addition to ROP improvements, losses did not prove prohibitive to reaching TD due to drilling efficiency. Subsequent further improvements in ROP have been realized, with the entire interval drilled at 16m/hr.
Lu, Xiao (The University of New South Wales) | Armstrong, Ryan (The University of New South Wales) | Yuan, Meng (The University of New South Wales) | Zhang, Yulai (The University of New South Wales) | Mostaghimi, Peyman (The University of New South Wales)
Coalbed methane (CBM), also known as coal seam gas, is becoming an increasingly important energy resource in the global natural gas market. Gas transport in CBM reservoirs remains a crucial research topic that has not been fully understood. Two scales of gas flow are identified in coal cores: flow in fractures and diffusion within matrix. The diffusion process is quantified by the gas diffusion coefficient while flow in fractures is governed by fracture apertures. This paper aims to explore the diffusion process in coal using X-ray microcomputed tomography (micro-CT) imaging. The experiments are conducted at 100 psi effective stress to eliminate the impact of pressure. The images obtained are registered for visualisation and analysis of the diffusion process and comparisons of fracture. In the paper, the impact of increasing effective stress on fracture aperture is demonstrated. Also, the diffusion coefficient of Krypton in coal matrix is estimated and discussed.
The Ceduna Sub-basin is one of the few remaining frontier basins in Australia today. Few exploration wells have been drilled in the basin and none have encountered hydrocarbons. The current study aims to investigate the hydrocarbon prospectivity of an area of interest (AOI) within the distal part of the Ceduna Sub-basin, where no well information is available.
The study uses 3D seismic data and employs principles from geophysics, structural geology, sedimentology, sequence stratigraphy, and petroleum systems analysis in a comprehensive investigation to understand the Ceduna Sub-basin. Multiple 2D basin models were created for the AOI to test different scenarios in a detailed risk analysis of the petroleum system and its major controls. They were identified from a comprehensive literature review and after a thorough interpretation of the 3D seismic survey in the AOI.
Results show that the best reservoir is located within the low stand systems tract (LST) deposits of the Hammerhead Sandstone (Ss) and Top Tiger Ss. The potential source rock occurs in the condensed high stand system tract (HST) deposits in the Base Tiger Ss and White Pointer Ss. 1D modeling showed that these source rocks may have generated hydrocarbons as their depth is <9 km. The critical moment during the source rock history was at 80 Ma coinciding with the deposition of the Hammerhead Ss.
Based on the regional structural framework, faults were initiated after source rock deposition. Several growth faults may pose a risk in terms of hydrocarbon leakage. Different 2D models have advanced the understanding of the petroleum systems in the AOI. The results showed that the most prospective areas are within a rollover anticline play and those areas where intra-formational seals are present. The model confirms that fault integrity represents the prime risk across the basin.
The current study contributes to understanding of the Ceduna Sub-basin by identifying two different plays in the AOI: rollover anticline and tilted fault block. Probability analysis of the different petroleum elements shows that the rollover anticline play has the highest geological probability of success.
This case study highlights the field-trial of a pump-out stage tool, pump-out float collar, and the annular casing packer. These technologies were integral to drilling and completing wells in the Santos coal-seam gas (CSG) development of the Roma field in the Surat Basin of southeast Queensland.
Pump-out systems—which allow a primary cementing job to be performed above a slotted casing string using a pump-out stage tool, annular casing packer, and pump-out float equipment—eliminate the need for drill out operations. Once the casing is landed, a ball is deployed from surface to actuate the inflation of an annular casing packer below the stage tool and above the slotted casing. A second ball is deployed to shear and shift a sleeve to open the stage tool and begin the primary cement job. Once complete, a cementing wiper plug is released from surface and pumped behind the cement slurry to shift the stage tool into the closed position. The internal pump-out casing components are displaced to the bottom of the well and require no further intervention.
This case history includes results of the initial field-trial runs and technical details on well configurations, slotted liner placement across the coal-bed intervals, pressure charts, cement-job data, shear information on the ball seat, detail on the stage-tool operation, pumping out the float collar, and displacement of the internal equipment downhole. These jobs planned to eliminate the need to run a dedicated drillout trip during initial completion and also the need to change out the pipe rams in the blowout preventer (BOP).
Ultimately, the pump-out system provides a full-bore casing geometry with no internal restrictions and is expected to reduce completion costs by 15%.
Flottmann, Thomas (Origin Energy) | Pandey, Vibhas (ConocoPhillips) | Ganpule, Sameer (Origin Energy) | Kirk-Burnnand, Elliot (Origin Energy) | Zadmehr, Massoud (Origin Energy) | Simms, Nick (Origin Energy) | Jenkinson, Jeslie George (Origin Energy) | Renwick-Cooke, Tristan (Origin Energy) | Tarenzi, Marco (Origin Energy) | Mishra, Ashok (ConocoPhillips)
Walloons Coals of the Surat Basin, Queensland (Australia) contain world class Coal Seam Gas (CSG) plays, where permeability varies from high ( 1Darcy), due to Gaussian curvature-related natural fracture connectivity, to low ( 1mD) due to unidirectional fracture-systems attributed to regional unidirectional flexure. The low permeability Walloons Coals require stimulation to unlock their gas resources. This contribution describes the design evolution of stimulation concepts in the Surat Basin in context of five key subsurface drivers 1. Coal net to gross: Surat Basin coals contain 30 coal seams with a cumulative thickness of 20-35m in a gross rock column of 300m 2. Permeability of coals requiring stimulation for economic flow rates varies from 1mD - 30mD 3. Varying stress regimes, both vertically and laterally 4. Ductile rock properties in Walloons coal reservoirs 5. Productivity Index drop (PI drop) can occur when (incompressible) water is replaced by (compressible) gas during coal dewatering Early stimulation treatments in Surat Basin (pre-2010) followed'standard' high rate water/sand designs adapted from the shale industry. However, high treating pressure and rates resulted in several instances of casing shear (Johnson et al. 2003) particularly at depths associated with stress regime transitions. Subsequent designs (2010-12) repeated water fracs albeit including ample diagnostics (Johnson et al 2010; Flottmann et al 2013), showing that water fracs appear to be ineffective in stimulating Walloons Coals. Design optimizations in 2015 (Kirk-Burnnand et al. 2015) based on extensive modeling work (Pandey and Flottmann 2015), identified low rate gel fracs as optimal to stimulate rocks with'ductile' Walloons-specific coal properties. However, treatment rates were limited to optimize height growth, both to connect coals and to avoid height growth into non-reservoir. Initial production data indicated a drop in well productivity in some fracture stimulated coals (Busetti et al. 2017). Consequently, stimulation designs were modified in late 2016 to account for such productivity drops while maximizing the fluid recovery.
Coal seam gas (CSG) well operators typically follow an industry rule of thumb 0.5 ft/s liquid velocity to prevent the onset of gas carryover during CSG dewatering operations. However, there is very little experimental data to validate this rule of thumb with only a publication by Sutton, Christiansen, Skinner and Wilson [
The University of Queensland Well Simulation Flow Facilities were designed to replicate as closely as possible the production zone of a typical vertical CSG well in Queensland, Australia in transparent acrylic pipes to observe two-phase flow behavior in simulated downhole conditions. The annular test section in the rig was constructed of a 7-in casing and 2¾-in tubing. Modification of the experimental setup to include a vertical separator allowed for the detection of gas carryover. Conceptual demonstrations of gas carryover were captured and have been illustrated. The experiments in this study validate the industry rule of thumb of 0.5 ft/s liquid velocity as an appropriate guideline for onset of gas carryover in a casing-tubing annulus dimension similar to a typical CSG well in Queensland.
Wetting properties of various reservoir rocks strongly influence the efficiency and security of geological storage of carbon dioxide in deep saline aquifers. Numerical simulation of Carbon Capture and Storage (CCS) has become a considerable research option now-a-days due to less time and cost-effective outcomes compare to traditional laboratory based experiments. This study provides a Computational Fluid Dynamics (CFD) methodology for the pore-scale displacement mechanism of supercritical CO2 under different wetting conditions and quantify the effect of wettability and direction of flow on supercritical CO2 trapping.
A 3-Dimensional visualization software is used to build surface mesh from the micro-pores of the Bentheimer sandstone. A module of a commercial CFD software is used to generate volume mesh from the surface mesh and another module from the same CFD software is used to perform imbibition processes (supercritical CO2/brine) through the Bentheimer sandstone. Full Navier-Stokes equations are solved by using Eulerian-Eulerian multiphase transient flow approach. Free surface flow model is used to integrate the effect of capillary forces. This model determines the pressure gradient at the two-phase interface. The flow is assumed to be laminar, isothermal and there is no mass transfer between phases.
The initial condition of the imbibition processes was obtained from a drainage process for a strongly water-wet system. For this, a Bentheimer sandstone was completely filled with brine and supercritical CO2 was injected. The simulation was stopped when brine was drained by supercritical CO2 and the system reached the steady state conditions. This phase distribution was used as an initial boundary condition for the imbibition processes. The imbibition processes were performed in two opposite direction for different contact angles (100° and 110°). The effect of wettability and direction of brine on supercritical CO2 trapping were observed. The residual saturation of supercritical CO2 was significantly different in two opposite direction of brine flow. In the reverse imbibition process, normalized residual supercritical CO2 saturation values are increased but, the amount of normalized trapped supercritical CO2 values are decreased. It was mainly due to the amount of normalized free supercritical CO2 saturation values (which were equal to the difference between normalized residual supercritical CO2 saturation and normalized free supercritical CO2 saturation values).