Following the significant reservoir depletion on Elgin / Franklin fields since 2007, drilling infill wells was considered to not only be high cost but also carry a high probability of failure to reach the well objective. The recent campaign on the Elgin field, one of the most heavily depleted reservoirs worldwide, demonstrated that infill drilling can be achieved safely while improving performance.
Drilling of HPHT infill wells on the Elgin field faced increasing challenges arising from the reduction of reservoir pressure that changed the stresses in the formations above and influenced the overall pressure regime. This stress reorganization in the overburden has affected the fracture network in these formations resulting in reduction in Fracture Initiation Pressure (FIP) and increase of gas levels.
Challenges were faced during the drilling of three wells in the 2015-2017 campaign. Loss events in Chalk formations in the intermediate sections significantly decreased the already Narrow Mud Weight Window (NMWW). A strategy to define and validate the minimum required MWW in 12-1/2" and 8-1/2" sections was developed following a complex subsurface well control event. Managed Pressure Drilling (MPD) technique was extensively used to safely manage gas levels and assess pore pressure.
Reservoir entry with more than 850 bar of overbalance remains the main challenge in infill drilling. A total loss event during first reservoir entry in the latest campaign confirmed the limitations of wellbore strengthening mud and stress caging materials available today.
Lessons learned from each well in this campaign were implemented to address these challenges and improve performance. This paper describes the Elgin HP/HT infill drilling experience and the specific techniques and practices that were developed to address these challenges and improve performance. The importance of Equivalent Circulating Density (ECD) management with very narrow MWW, successful high gas level management with MPD and depleted reservoir entry, shows that even in a highly complex environment, drilling performance can be improved allowing for further economical development drilling. The successful and safe delivery of the Elgin 2015-2017 infill drilling campaign demonstrates this at a time the industry moves toward unlocking the reserves of more challenging HPHT fields.
Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
Deep HPHT gas/condensate wells drilled and completed in open hole with cesium formate fluids clean-up naturally over hours and sometime days after initial production start-up as the wells unload water-based fluids and filter-cake from the reservoir zone. Following natural flowing clean-up during the start-up phase the wells tend to be highly productive, with low skins, and over the long-term those fields developed entirely and solely with cesium formate fluids have a reputation for delivering the recoverable hydrocarbon reserves projected in the operators' original business plans.
Laboratory core flooding tests with cesium formate fluids attempt to simulate real well clean-ups by applying drawdown pressures across the cores to create a cleansing flow of gas or oil to bring the rock permeability back to original native levels. Such attempts are usually successful in cores flooded with clear cesium formate brines, but it is rare to hear of cores that have cleaned up 100% after long duration exposure to cesium formate drilling fluids without subsequent mild stimulation with water or dilute acid. The persistent lack of congruence between observed well clean up performance and core flooding test results with cesium formate drilling fluids suggests that the attempted laboratory simulations of natural well clean up under drawdown might be inadequate or flawed in some way. One point of concern thought worthy of further investigation has been the duration of the drawdown-induced gas or oil flows applied in laboratory core flood tests to restore permeability. Wells have the opportunity to gradually clean up over years during production while laboratory clean ups by drawdown may only be applied for minutes or hours.
The objective of the study described in this paper was to review old core flood test data to see how quickly the simulated well clean-up procedures restored original permeability in tight gas-bearing sandstone cores after exposure to high-density cesium formate fluids for at least 48 hours under HPHT conditions.
Plugs of gas-bearing low permeability (2-20 mD) sandstone containing simulated formation water at irreducible water saturation were exposed to overbalanced cesium formate fluids for 48-96 hours under HPHT reservoir conditions. The plugs were then subjected to drawdown regimes with nitrogen gas, under HPHT reservoir conditions, to simulate formation and filter-cake clean-up of an open-hole deep gas well completion at production start-up. Fluid and gas flow rates, and differential pressures across the plug, were logged whenever flow was induced through the plug, to allow estimation of the relative permeability changes in the rock throughout the test sequence.
Results were compared for HPHT core flooding tests with: 10 pore volumes of SG 2.20 cesium formate completion brine pushed through 2 mD sandstone plugs at 200° C and high pressure, followed by a 48-hour static soak period under the same conditions. 10 pore volumes of SG 2.20 cesium formate completion brine pushed through 20 mD sandstone plugs at 175°C, followed by a 48-hour static soak period under the same conditions. SG 1.76 potassium/cesium formate drilling fluid circulated at 500 psi overbalance for 48 hours across the face of a 20 mD sandstone plug at 150°C, and then left static for a further 48 hours, resulting in 1.2 pore volumes of fluid loss through the core.
10 pore volumes of SG 2.20 cesium formate completion brine pushed through 2 mD sandstone plugs at 200° C and high pressure, followed by a 48-hour static soak period under the same conditions.
10 pore volumes of SG 2.20 cesium formate completion brine pushed through 20 mD sandstone plugs at 175°C, followed by a 48-hour static soak period under the same conditions.
SG 1.76 potassium/cesium formate drilling fluid circulated at 500 psi overbalance for 48 hours across the face of a 20 mD sandstone plug at 150°C, and then left static for a further 48 hours, resulting in 1.2 pore volumes of fluid loss through the core.
The straight cesium formate brines were removed quite promptly, typically within 15-30 minutes, from the 2-20 mD rock cores during drawdown. In the test with 20 mD sandstone plug and cesium formate drilling fluid the drawdown pressures were ramped up in stages from 1 psi to 100 psi during the clean-up phase but the rock plug was slower to regain its permeability. After 96 minutes of drawdown the plug had only recovered 79% of its initial relative gas permeability and clearly it was still in the process of cleaning up.
The test results provide new information about the clean-up rate of low permeability rock cores invaded by heavy cesium formate fluids under HPHT conditions and subjected to drawdown with gas.
Increases in high pressure, high temperature (HPHT) drilling campaigns on the continental shelf of Norway and the UK have increased demands for next-generation technology that can deliver borehole measurements, enabling the wells to be drilled and reducing the operator's risk and operational expense. These deep gas development and exploration wells require a dramatic departure from conventional operating envelopes, including pressure, temperature, hydraulics, and formation evaluation capability.
This paper looks, rather uniquely, at an HPHT field in the UK Sector of the North Sea which was designed and developed during the mid 1990's and which, relatively recently, gave problems due to a gas leak from a well which was being worked on. The amount of gas emitted from the well caused full evacuation and the fact that the problem was solved with no injury gives full testimony to the high standard of the Operators Policies and Procedures. The well was killed from the top and a relief well was also drilled, designed to kill the well from the bottom. Unfortunately, the cost of a) loss of production and b) remedial works ran into £billions and the Operator was fined £1,125 million by the Law Courts for contravening the Health & Safety at work act. Sometimes, during the early design phases of a project company departments make decisions which turn out to be less than optimal simply because certain information wasn't known. This can be unfortunate and very costly. The field, Elgin, was named after a relatively nearby Scottish town. The field forms a part of the Central Graben and there were essentially two reservoir columns (the Jurassic overlying the Pentland). The paper tries to portray the excellence of planning, management and operations exhibited by the current world class / first rate Operator.
Baraka-Lokmane, S. (Total) | Hurtevent, C. (Total) | Rossiter, M. (Total) | Bryce, F. (Total) | Lepoivre, F. (Université de Lyon) | Marais, A. (Université de Lyon) | Tillement, O. (Université de Lyon) | Simpson, C. (Scaled Solutions Limited) | Graham, G. M. (Scaled Solutions Limited)
Numerous challenges exist in Total's Central Graben Area (CGA). The main reason being that they present extremely "hard" conditions: high temperature (with 195°C to 225°C due to reverse Joule Thomson effect), high pressure (with 1,100 bar), high salinity (with more than 250g/L in TDS, more than 20g/L in calcium and circa 450mg/L in iron) along with several scale types (with sodium chloride, calcium carbonate, zinc sulphide and lead sulphide).
In the wells of CGA fields, the highest scaling risk is the formation of sulphide scale in the subsurface safety valve region. Commercially available scale inhibitors have proven incapable to perform under such "hard conditions" (see SPE 173761).
This paper describes the design process of suitable new chemicals (scale inhibitors and nanoparticles scale inhibitors) for both downhole continuous injection and squeeze treatment applications.
Such compounds are based on cationic polymers and sulphonated anionic polymers. A chemical approach has been used for the synthesis of silica nanoparticles. The sol-gel method, in addition to its low cost, allows controlling both the size and morphology of the particles by varying certain parameters of the reaction. Extensive laboratory tests have been performed for the validation of these products; these tests include scale inhibitor/brine compatibility, static and dynamic tests, thermal ageing, post ageing analysis and performance tests as well as coreflood tests using real core from the CGA formations. These laboratory testing have allowed the tuning of the chemical design of these novel products in order to improve the performance and the thermal-stability.
This paper describes the considerable advancement in chemical performance under these extreme conditions, including specific test development for lead sulphide which has to date proven more difficult than other sulphide scales to assess under field representative conditions in the laboratory. The newly developed chemicals are now ready for trial on the field.
This study has been focusing on planning wells, which target lower Pleistocene reservoirs below a depleted Ha'py gas field. Many Non Productive time events (NPT) have been anticipated, and the challenges of losing wells and running over budget have been considered as major risks in targeting the deeper prospects.
Years of production from the main Pleistocene A20 reservoir has resulted in significant pressure depletion, while underlying largely-undeveloped Pleistocene reservoirs appear to be very promising they remain at or close to virgin conditions. In addition, the position of the platform at the centre of the field has made it necessary to drill highly-deviated wells to access remaining reserves at the crest of the field.
Detailed planning and close collaboration between the PhPC (Pharaonic Petroleum Company) subsurface and drilling teams has been necessary to understand the geological and geomechanical properties of the key formations. This has helped in selecting appropriate mud rheology and mud additives in addition to ensuring good drilling practices that maximise safety and success. The combined effects of depletion and low rock strength make it effectively impossible to drill the A20 interval with the mud weights required to minimize well bore instability. As a result, stress cage additives were employed in the drilling mud in order to reduce the potential for losses due to the large overbalance against the depleted sand. Modeling prior to drilling suggested this application lay close to the technical limit of the stress cage methodology, and was beyond anything previously attempted within the Pleistocene reservoirs in the offshore Nile Delta.
Careful execution meant we were able to successfully drill through the depleted zone, and as a result of this work, we have been able to deepen recent wells to access underlying gas resources. This success has allowed us to reduce NPT while ensuring safe well operations.
Baraka-Lokmane, Salima (TOTAL) | Hurtevent, Christian (TOTAL) | Zhou, Honggang (TOTAL) | Saha, Pratik (TOTAL) | Tots, Nourdine (TOTAL) | Rieu, Frédéric (TOTAL) | Lastennet, Ronan (TOTAL) | Sugiarto, Tomi (TOTAL)
In Central Graben, North Sea, there is generally no free water production, most of the produced water is condensed water; however wells have been treated against scale build up at perforation level by performing acid washes using mainly acetic acid. Wells reacted differently after acid treatment: Some wells showed a significant productivity improvement, others showed good results but limited in time, some wells presented no gain after acid treatment and some other wells are scaling on a more aggressive basis after acidification. This paper shows that these behaviours are linked with the lithology of the different reservoirs. A better understanding on the scale formation and mechanism is essential in order to optimize the well intervention planning and timing to treat the wells. This study showed that calcium carbonate and sodium chloride are the only scale deposits susceptible to precipitate at the bottomholes of wells. The precipitation of sodium chloride has been induced by the high salinity of water associated with a high temperature at bottomholes as well as an inversion of the Joule- Thomson coefficient. Calculations showed that evaporation is slightly higher for Elgin reservoirs comparing to Franklin reservoirs, this is due to Joule-Thomson effect slightly stronger and a higher temperature reservoir for Elgin reservoirs. These high temperatures at the bottomholes induced the formation of calcium carbonate precipitation, this conducted to the loss of productivity. From the subsurface safety valve (SCSSV) to the surface facilities, the reduction of temperature caused a reduction of solubility of zinc sulphide and lead sulphide. In terms of chronology, halite scale occurred first, followed by carbonate scale and finally formation of sulphide scale at lower temperature.
Okocha, Cyril (Heriot-Watt University) | Sorbie, Kenneth S. (Heriot-Watt University) | Hurtevent, Christian (Total Pau France) | Baraka-Lokmane, Salima (Total Pau France) | Rossiter, Marcus (Total E&P Aberdeen U.K)
Identifying effective sulphide scale squeeze inhibitors has been a major challenge in the production of oil and gas from deeper, higher temperature reservoirs. Managing sulphide scales of zinc and lead (ZnS and PbS) that commonly occurs in deep, hot reservoirs poses a significant challenge because of their very low solubilities. In general, for scaling problems applying chemical scale inhibitors or dispersants is the preferred solution to most challenges. However, to date no effective sulphide inhibitors/dispersants have been available which can deal with severe lead, zinc and iron sulphide problems at high salinity (HS 200, 000TDS) and high temperature (HT 180 C) conditions. It is a particularly difficult task to find sulphide inhibitors which can also be "squeezed" successfully since they must return to the wellbore at relatively high concentrations. This paper describes various sulphide inhibitor testing techniques which have been applied to many candidate products for the management of ZnS and PbS in a gas condensate field with a known relatively severe ZnS/PbS scaling problem. The paper presents sulphide static and dynamic test measurements along with thermal ageing results that show some encouraging results in terms of ZnS/PbS sulphide inhibition. The paper extends our knowledge and ability to test effective sulphide inhibitors for severe ZnS/PbS scaling conditions in high pressure/high temperature (HPHT) reservoirs.
Elgin offshore installation is located in the North Sea, approximately 200 km east of Aberdeen, Scotland, in a water depth of 92m. The facilities consist of a Process, Utilities and Accommodation platform with a bridge linked WellHead Platform (WHP).
On 25th March 2012, Well G4 on the Elgin WHP suffered an uncontrolled release of hydrocarbons to atmosphere. This resulted in a full evacuation from the installation and from the adjacent drilling rig.
Following this, access was re-gained to the platform by well control specialists. Well G4 was killed with heavy mud on 15th May 2012, which allowed routine personnel to return to the platform.
Production was re-started from Elgin on 9th March 2013, following a comprehensive re-assessment of the risks from the wells by Total E&P. This involved demonstrating that risks from the wells to personnel have been reduced to a level which is As Low As Reasonably Practicable, and was formally assessed by UK regulatory authorities via the “Safety Case”.
This paper focuses on what happened, lessons learnt and measures which have been put in place to prevent recurrence. More specifically, this paper will describe:
the incident itself in terms of the uncontrolled hydrocarbon release which occurred
the downhole failure and associated leak path which resulted in the release to atmosphere
the investigation carried out and the associated “immediate” and “contributory” causes
the lessons learnt from the G4 incident
the work required to return the production facilities to a fit-for-purpose condition
the re-evaluation of well integrity, and the development of well integrity “criteria”
the re-evaluation of the risks from wells which involved re-assessing the likelihood of a release from the wells and potential consequences should a release occur
how the lessons from the G4 incident are being implemented in terms of activities offshore, and in terms of updates to the Total E&P UK Company Management System
the role of the Safety Case and how it was used to demonstrate to UK regulatory authorities and to the offshore workforce that production could be safely restarted.