CML (Controlled Mud Level) is a dual gradient type of Managed Pressure Drilling (MPD). The CML system was developed and implemented on the Troll field to allow for reducing the annular pressures acting on the wellbore during drilling, thus allowing drilling areas weakened by faults and fractures and longer horizontal sections in the depleted normal pressured reservoirs. This paper will present a short introduction to the Troll field, a description of the system utilized, a summary of the rig integration, operations and experiences with the CML system on Troll.
Equinor drilling operations at the giant Johan Sverdrup field, where production is slated to start up this year. Similar development opportunities will be needed to sustain Norwegian production through the next decade. Norway’s energy ministry on 15 January awarded 83 production licenses in the North, Norwegian, and Barents Seas to 33 firms, topping the country’s year-old record of most licenses awarded in a round. Native operators Equinor, Aker BP, DNO, and Lundin Petroleum were leaders among a group spanning large, multinational firms and smaller European independents focused on the Norwegian Continental Shelf. The licenses, distributed as part of the Awards in Predefined Areas (APA) 2018 round, cover already-explored areas where existing knowledge and facilities can be leveraged to find and develop new oil and gas deposits.
Offshore wells drilled in the central and northern North Sea have historically suffered from borehole-instability problems when intersecting the Upper/Lower Lark and Horda Shale formations using either water-based mud (WBM) or oil-based mud (OBM). A wellbore-stability investigation was performed that focused primarily on improving shale/fluid compatibility. It was augmented by a look-back analysis of historical drilling operations to help identify practical solutions to the borehole-instability problems.
An experimental rock-mechanics and shale/fluid-compatibility investigation was performed featuring X-ray-diffraction (XRD) and cation-exchange-capacity (CEC) characterizations, shale accretion, cuttings dispersion, mud-pressure transmission, and a new type of borehole-collapse test for 10 different mud systems [WBM, OBM, and high-performance WBM (HP-WBM)]. The results of this investigation were then combined with the results of a well look-back study. The integrated study clearly identified the root cause(s) of historical well problems and highlighted practical solutions that were subsequently implemented in the field.
The borehole-instability problems in the Lark and Horda Shales have a characteristic time dependency, with wellbore cavings occurring after 3 to 5 days of openhole time. The problems were not related to mud-weight selection but were instead caused by mud-pressure invasion into the shales, which destabilizes them over time. An experimental testing program revealed that this effect occurs in both WBM and OBM to an equal extent, which explains why nonoptimal field performance has historically been obtained with both types of mud systems. New HP-WBM formulations were identified that improve upon the mud-pressure invasion and borehole-collapse behavior of conventional OBM and WBM systems, yielding extended openhole time that allows the hole sections in the Lark and Horda Shales to be drilled, cased, and cemented without triggering large-scale instability. Look-back analysis also indicated that secondary causes of wellbore instability, such as barite sag, backreaming, and associated drillstring vibrations, should be minimized for optimal drilling performance. A new HP-WBM system, together with improved operational guidelines, was successfully implemented in the field, and the results are reported here.
Antonsen, Frank (Statoil) | De Oliveira, Maria Emilia Teixeira (Statoil) | Hermanrud, Kristine (Statoil) | Luna, Carlos Aizprua (Statoil) | Petersen, Steen Agerlin (Statoil) | Metcalfe, Richard William (Statoil) | Constable, Monica Vik (Statoil) | Alme, Arvid (Statoil) | Vee, Torill (Statoil) | Salim, Diogo (Schlumberger) | Denichou, Jean-Michel (Schlumberger) | Seydoux, Jean (Schlumberger) | Omeragic, Dzevat (Schlumberger) | Thiel, Michael (Schlumberger) | Etchebes, Marie (Schlumberger)
The Byrding asset on the Norwegian Continental Shelf (NCS) successfully drilled a two-branched horizontal producer in a structuraly complex area with many faults, changes in reservoir properties laterally, and an uncertainty on oil-water contact (OWC) levels along the trajectories. The key inputs for optimal well placement of the two branches were measurements to map the reservoir top while drilling and the OWC up to approximately 20 - 30m TVD from the wellbore.
Before deploying the ultra-deep directional resistivity tool, it was critical before drilling to evaluate how top reservoir and OWC would be mapped by inversion of electromagnetic measurements. The reservoir conditions were challenging with a low resistivity contrast towards reservoir top and a gradually changing resistivity towards the OWC. It was, therefore, critical in the pre-job phase to help all involved in the future geosteering operation to get familiar with using the ultra-deep resistivity real-time interpretation to meet the objectives and to update the geomodel after drilling.
To plan the well placement job a new workflow was applied to build a realistic geomodel based on geological understanding, legacy offset wells measurements, and seismic interpretations. Then potential scenarios generated from this geomodel were used to simulate synthetic ultra-deep directional resistivity responses and inversions results, synthetic standard LWD-data, and seismic. Finally, an updated geomodel was built after the drilling campaign, validated through "Model-Compare-Update" traditional iterative process using synthetic and real data.
In conclusion, the pre-job analysis was important to understand how to interpret reservoir top and OWC. This knowledge was used in real-time while drilling and post-operation to update reservoir top interpretation and the OWC position. This case study describes the importance of having a workflow to build a realistic high resolution geomodel that is validated with all the subsurface measurements at different scales. Deployment of such highly integrated workflow open new horizon for the collaboration between service company and operator for improved pre-job planning, real-time decisions and post-job integrated interpretation. Furthermore, integrated interpretation of data from the two wells with seismic performed over the post drilling analysis is proven to be essential to ensure future production steering of the two-branched horizontal producers.
An alternative ultra-deep azimuthal resistivity inversion algorithm was successfully used while drilling along with the standard inversion to better interpret reservoir top in the context of low resistivity contrast from this case study. An important, and unprecedented effort of pre-job planning was conducted to select optimal LWD real time dataset required. IT and "cross-platform-data-exchange" challenges were overcome to allow an extensive and innovative use of realistic geomodel scenarii for multiple measurements simulation, including from synthetic ultra-deep resistivity inversions results, standard LWD-data, to seismic interpretation.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 184716, “Successful Multiwell Deployment of a New Abandonment System for a Major Operator,” by Thore Andre Stokkeland and Jim McNicol, Archer Oiltools, and Gary McWilliam, Maersk Oil, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, The Netherlands, 14–16 March. The paper has not been peer reviewed.
A new downhole-tool-based abandonment system was developed and deployed successfully on four wells for a major operator on a field in the North Sea. The operations were executed with each well taking less than 18.5 hours to secure. The successful operation saved the major operator considerable time and expense by eliminating the need for cutting and pulling the 10¾-in. casing to remove the oil-based mud (OBM) from the annulus before removing the wellheads.
Service companies were challenged by a major operator to create a solution to set a barrier against the overburden and to circulate OBM out of the annulus between the 10¾- and 13⅜-in. casings before pulling the wellhead.
The first stage of the operation was to run a perforation gun loaded for 1 ft with 18 shots/ft (spf) of a proprietary abandonment charge (single-casing perforation gun) to immediately below the wellhead at 475 ft. Then, the 10¾-in. casing was perforated with 0.8-in.-diameter holes without damaging the 13⅜-in. casing to create a circulation path.
The second stage was to run a retrievable bridge plug (RBP) with another 1-ft-long perforation gun below. The RBP was set and perforated immediately above the 13⅜-in. shoe at 2,300 ft; then, circulation was established up to the shallow perforations above and the OBM in the 10¾- by 13⅜-in. annulus was circulated out. After the circulation parameters were established, a wash pill was pumped around the annulus to clean out the OBM.
The third step was to set the actual overburden barrier in the A and B annuli. This was achieved by displacing cement through the ball valve of the RBP into the perforations below the RBP, placing the cement plug below and into the 10¾- by 13⅜-in. annulus. The ball valve was closed, and a cement plug was pumped on top of the RBP, completing the barrier.
The North Sea’s Leadon Field lies in 370 ft of water and is located in Blocks 9/14a and 9/14b of the UK Continental Shelf approximately 220 miles northeast of Aberdeen. Field development was enabled by the addition of two satellite fields, Birse and Glassel. The three fields were developed with subsea horizontal wells tied back to a floating production, storage, and offloading facility. The Lark and Horda formations produce in two well clusters, A and B. Cluster A has seven production wells and two water injectors; Cluster B consists of three production wells, two water injectors, and two aquifer wells. Both clusters have space for additional wells.
After a commercially successful period, production eventually declined, leading to a Cessation of Production Application being filed by the operator in 2004. A decommissioning program for the field was approved in March 2016.
Davison, J. M. (Shell Global Solutions International B.V.) | Salehabadi, M. (Shell UK Exploration & Production) | De Gennaro, S. (Shell UK Exploration & Production) | Wilkinson, D. (Shell UK Exploration & Production) | Hogg, H. (Shell UK Exploration & Production) | Hunter, C. (Shell UK Exploration & Production) | Schutjens, P. (Shell Global Solutions International B.V.)
ABSTRACT: At the end of field life, wells require permanent plugging and abandonment (P&A) as part of decommissioning activities. Some UK fields developed in the 1970’s are reaching their end of field life, with UK industry estimates predicting well P&A costs over the next 30-40 years of 24 billion dollars. As well as the high financial cost, there is a significant HSSE exposure to ensure safe and reliable P&A such that no escape of hydrocarbons is possible to the near surface environment.
This paper discusses the role Geomechanics has to play in potentially reducing well P&A costs, but also ensuring integrity of the wells and formations over long time scales. Recent experience in the UK North Sea has highlighted the requirement for detailed geomechanical knowledge of the field. We will focus on three key areas for geomechanical analysis. Firstly, we discuss reservoir pressure re-charge and in-situ stress response, from simple pressure-depth plots to more complex 3-D numerical modelling of the stress changes in reservoirs and surrounding formations. An added level of complexity compared to ‘conventional’ geomechanical modelling is the ability to forward predict the reservoir pressure recharge over hundreds of years and the commensurate response of the in-situ stresses. Secondly, as well as the modelling of stress changes over time, Geomechanics has a key role to play in determining the opportunity of using shale creep deformation to create annular barriers in the place of cement. Lastly, in some cases the preferred P&A design for a well is not possible due to well access issues which then requires cross-flow analysis linked with the geomechanical response of permeable formations. This approach is required for containment risk assessment and application of ‘as low as reasonably practicable’ (ALARP) assessments for well and formation integrity. Each of these subjects will be covered with field examples from the UK North Sea which demonstrate the Geomechanical workflows employed and the impact these have had on the business.
Service companies were challenged by a major operator to come up with a solution to set a barrier against the overburden and to circulate oil based mud out of the annulus between the 10-3/4 in. and 13-3/8 in. casings before pulling the wellhead. The most common industry solution to this challenge is to cut the 10-3/4 in. casing by the 13-3/8 in. shoe and pull the casing to surface. An innovative new downhole tool based abandonment system was developed and successfully deployed to meet this objective.
The first stage of the operation was to run a perforation gun loaded with one foot of 18 shots per foot of a proprietary abandonment charge (single casing perforation gun) to just below the wellhead at 475 ft. Then perforate the 10-3/4 in. casing with 0.8 inch diameter holes without damaging the 13-3/8 in. casing behind, to create a circulation path.
The second stage was to run a V0 rated Retrievable Bridge Plug, RBP, with another one foot long perforation gun below. Set the V0 rated RBP and perforate just above the 13-3/8 in. shoe at 2,300 ft. then establish circulation up to the shallow perforations above and circulate out the oil based mud in the 10-3/4 in. by 13-3/8 in. annulus above. After the circulation parameters were established, a wash pill was pumped around the annulus to clean out all the oil based mud.
The third step was to set the actual overburden barrier in both the A and B annulus. This was done by displacing cement through the ball valve of the V0 rated RBP into the perforations below the RBP; placing the cement plug below and into the 10-3/4 in. × 13-3/8 in. annulus. The ball valve was closed and a cement plug was pumped on top of the RBP completing the barrier. The barrier was verified by pressure testing through the shallow perforations to 1,000 psi above the seawater gradient. A barrier was in place in both A and B annuli.
This procedure was deployed on four wells for a major operator on the Leadon South Field in the North Sea with great success. The operations were flawlessly executed with each well taking less than 18.5 hours to secure. The successful operation saved the major operator considerable time and expense by eliminating the need for cutting and pulling the 10-3/4 in. casing to get the oil based mud out of the annulus before removing the wellheads.
This paper provides an overview of the innovative new abandonment system elements and describes the successful deployment operation in detail.
Tor/Ekofisk wells drilled in the Danish sector of the North Sea have historically suffered from borehole instability problems when intersecting the Upper/Lower Lark and Horda shale formations using either water-based mud (WBM) or oil-based mud (OBM). An extensive wellbore stability investigation was carried out, focused primarily on improving shale-fluid compatibility. It was augmented by a lookback analysis of historical drilling operations in order to identify practical solutions to the borehole instability problems.
A state-of-the-art experimental rock mechanics and shale-fluids compatibility investigation was carried out featuring X-ray diffraction and cation exchange capacity characterizations, shale accretion, cuttings dispersion, mud pressure transmission and a new type of borehole collapse test for 11 different mud systems (WBM, OBM and high-performance WBM). The results of this investigation were then combined with the results of a comprehensive well lookback study. The integrated study clearly identified the root cause(s) of the Tor/Ekofisk well problems and highlighted comprehensive practical solutions, which were subsequently implemented in the field.
The borehole instability problems at Tor/Ekofisk in the Lark/Horda shales have a characteristic time-dependency, with wellbore cavings occurring after 3-5 days of open-hole time. The problems were not related to mud weight selection, but were instead caused by mud pressure invasion into the shales, which destabilizes them over time. An extensive experimental testing program revealed that this effect occurs in both WBM and OBM to equal extent, which explains why non-optimum field performance has historically been obtained with both types of mud systems. New highperformance WBM (HP-WBM) formulations were identified that significantly improve upon the mud pressure invasion and borehole collapse behavior of conventional OBM and WBM systems, yielding extended open hole time that would allow the hole sections in the Lark/Horda shales to be drilled, cased and cemented without triggering large-scale instability. Lookback review also indicated that secondary causes of wellbore instability, such as barite sag, extensive backreaming and associate drillstring vibrations should be minimized for optimum drilling performance. A new HPWBM system, together with improved operational guidelines, was successfully implemented in the field.
We have used two different approaches for net-uplift estimation. First we used sandstone modeling by integrated cement estimation and rock physics modeling with burial history. Secondly we derived net-uplift estimates from interval velocities, using a background trend calibrated for Eocene shales. This approach results in a 2D map with more spacious and structural information included. The shale modeling reconstructs a close to flat pre-uplift BCU surface, as we would expect, while results from the sandstone modeling differs from this at one of the Troll Field wells. Nevertheless, we obtain similar net-uplift estimates using two separate methods, with results relevant for further use in several aspects related to risk assessment in exploration such as seismic response and AVO prediction, along with important information related to generation, migration and accumulation of hydrocarbons.
Presentation Date: Wednesday, October 19, 2016
Start Time: 1:55:00 PM
Presentation Type: ORAL
Development study can be challenging when limited data is available, but cross-discipline interaction can greatly help to improve the understanding of the reservoir architecture.
A small undeveloped North Sea turbidite field, discovered in the 1980s, was recently revisited as part of a feasibility study. Two historical wells suggested the existence of thin sand beds three to five feet thick, however seismic attribute maps were inconclusive in distinguishing whether the sands were deposited as deep marine slope feeder channels or as turbidite fans. Geochemical and pressure data differences from the wells indicated a possibility of compartmentalization. The NtG estimated from the wells ranged between 10-30%, and as such large uncertainties exist in the reservoir properties and lateral extent.
Data available across all disciplines was integrated to define a range of possible Mutually Exclusive and Collectively Exhaustive field conceptual models. These were created by combining deep marine channels and turbidite lobe reservoir geometries. Sector models for both geometries were constructed and dynamically simulated to understand their impacts on recovery factor. The conclusions were used to calibrate the conceptual models and also to choose deterministic models representing low, mid and high case recoverable volumes.
An uncertainty of fluid-fill in the reservoir existed as the wells did not log fluid-contacts and had different RFT pressures. Multiple fluid-contact realizations were built that ranged from spill-point-based contacts to free water level. Realizations with perched water and stratigraphically trapped oil columns were constructed and then discarded, as the base reservoir required uplift which was greater than the seismic depth uncertainty. The realizations defined for sand distribution and fluid contacts were probabilistically combined to define the low, mid and high case realization models for the dynamic simulation. This integrated workflow helped define the worst and best case scenarios for the highly heterogeneous system with limited data.
The introduction of a small field allowance in the United Kingdom  has encouraged companies to revisit previously discovered fields for potential development. Many of these small fields were discovered in the 1980’s and 1990’s and have limited appraisal data, resulting in large sub-surface uncertainties. This makes the development planning quite challenging as smaller volumes in these fields often result in marginal economics. At the same time however, they offer a cheap development opportunity though a tie-in to a nearby facility. Such tie-ins also help in extending the life of the existing fields and facilities, thereby increasing overall value for the company.
Shell recently completed a development feasibility study for a small field, Field X located in North Sea, for possible tie-in with a nearby facility. The field was discovered in the 1980’s and large sub-surface uncertainties exist in reservoir extent, fluid contacts and reservoir properties. An integrated study was carried out to define sub-surface models that honored the available dataset and also captured the uncertainty range i.e. models being Mutually Exclusive and Collectively Exhaustive. These sub-surface models were then used in dynamic realm to understand the impact of dynamic uncertainties like aquifer strength, size of the gas cap and relative permeability with an overall objective of generating low, mid and high production forecasts.