Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
Challenging conditions in a HP/HT well in the UK Central North Sea, led to the deployment of a contingent expandable liner. Under-reaming tools were needed to facilitate running of the contingent liner. Under-reaming operations are associated with a degree of uncertainty on the final hole diameter. A technology was deployed to monitor cutter position, wear and vibrations. With the aim of removing the above uncertainty. An open-hole calliper run was performed to validate the technology.
The monitoring system utilizes an arrangement of sensors to measure variables that are critical to under-reaming operations. The sensors are housed within the expandable cutting structure of the under-reamer and comprises of a cutter block position indicator and a PDC cutting structure wear sensor. The monitoring system can also record downhole dynamics at the under-reamer. The system can therefore determine, via memory data, the actual under-reamer extension size at any point during the run, therefore allowing the minimum hole diameter to be derived. Providing immediate feedback at the rig site once the tool is at surface.
The first run globally of the 12 ¼" × 14" size is presented, the monitoring system recorded 187 hrs of data. The cutter blocks position sensor showed the cutting structure was fully expanded as required whilst pumping at drilling flow rate once the tool was activated. The wear sensors were fully active and showed no wear for the duration of the systems battery life. A combination of the positional and wear sensors indicated full gauge hole to the recorded depth. Due to the type of contingent liner the delivery of gauge hole was critical. As such, the data was validated using a dedicated open-hole calliper run on wireline. The calliper confirmed the open-hole diameter calculated based on data provided by the wear and position sensors. Based on this result the requirement for an open-hole calliper run can be reconsidered. In addition, the acceleration recorded was well correlated with the MWD recorded vibration data and allowed parameter recommendations to be generated.
The ability to monitor the position and status of the under-reamer cutting structure eliminates uncertainty on the final hole size following under-reaming operations and identifies any problem areas and their probable causes prior to running casing/liner. In turn this has the potential to eliminate the need for wireline runs and therefore reduce the open-hole time in a potentially unstable formation.
This paper is based on the analysis of the ultrasonic/sonic data of the 9 5/8-in. casing logging of the 14 wells of the Varg field within the Norwegian Continental Shelf. While writing this papper Varg field was undergoing a plug and abandonment (P&A) phase after 19 years of production. High-quality bonding is observed behind the 9 5/8-in. casing far above expected theoretical top of cement within single casing areas. This bonding is attributed to the formation influence. Formation is used as an alternative to traditional cement barriers during P&A, and its use is regulated by the legislation.
The paper aims to develop better understanding of the mechanisms responsible for formation bonding development. The percentage of observed bonding at "high" and "high and moderate-to-high" quality is calculated within each well and is related to the various factors that could influence formation bonding development. Factors such as duration of time lapsed from well completion to well logging, type of well (producer versus injector), geological formation, type of drilling mud used, duration of production periods, volumes of production, and well deviation and azimuth were looked at to determine observable trends and relationships.
The results of the study allowed us to conclude which factors are critical or influence formation bonding. Based on the observations, recommendations can be made for the selection of the first well to be logged on the planned P&A campaigns. Correct selection of the first well saves time and resources on the formation testing for the qualification of the formation as a barrier.
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.
A high level of reservoir depletion (greater than 8,000 psi) has resulted in significant changes to the drilling envelope that has added complexity to the drilling practices required to exploit the remaining reserves successfully. Managed-pressure-drilling (MPD) technology was implemented in conjunction with drill-in liner and wellbore-strengthening technologies to successfully deliver the first well in a redevelopment campaign and prove the techniques required to prolong field life. Shearwater is an HP/HT gas/condensate field discovered in 1988. Primary production is from the Fulmar, a sandstone reservoir with virgin pressure of 15,400 psi and temperatures greater than 360 F. The field came on stream in 2001. The large field-pressure depletion resulted in compaction at the Fulmar formation level and led to mechanical failure of the production liners because of shear deformation.
Produced water chemical compositional data are collected from a carbonate reservoir which had been flooded by North Seawater for more than 20 years, so there is an opportunity to analyse the large amount of produced water data collected, understand the brine/brine and brine/rock interactions and explore the impact factors behind them. In some publications, core flood experimental tests were performed with chalk cores or carbonate columns in order to make an understanding of possible chemical reactions occurring triggered by injected water with different composition (Seawater, low salinity water or any other brine). However, most of the time the laboratory conditions where core flooding experiments are implemented cannot fully simulate the real reservoir conditions. Therefore, in this study, with the help of the valuable produced water dataset and some basic reservoir properties, a one-dimensional reactive transport model is developed to identify what in situ reactions were taking place in the carbonate reservoir triggered by seawater injection.
From the perspective of reservoir mineralogy, calcite, as the dominant mineral in the carbonate reservoir, is relatively more chemically reactive than quartz and feldspar which are usually found in sandstone. Whether calcite is initially and dominantly present in the carbonate reservoir rock is dissolved under seawater flooding or not is the first key issue we focused on. The effects of calcite dissolution on the sulphate scaling reactions due to incompatible brine mixing and the potential occurrence of carbonate mineral precipitation induced by calcite dissolution are investigated and discussed in detail. The comparison of simulation results from the isothermal model and the non-isothermal model show the important role of temperature during geochemical processes. The partitioning of CO2 from the hydrocarbon phase into injected brine was considered through calculation of the composition of reacted seawater equilibrated with the CO2 gas phase with fixed partial pressure (equivalent with CO2 content), then subsequently the impact of CO2 interactions on the calcite, dolomite and huntite mineral reactions are studied and explained. We also use calculation results from the model to match the observed field data to demonstrate the possibility of ion exchange occurring in the chalk reservoir.
Carbon dioxide injection has recently been considered as a promising method for enhanced oil recovery. The supercritical carbon dioxide is often miscible or nearly miscible with the oil under reservoir conditions, which facilitates high recovery. Underground injection of carbon dioxide is also of a significant ecological advantage, and utilization of CO2 results in a noticeable reduction of the taxation of the petroleum companies. On the other hand, application of carbon dioxide under conditions of the North Sea petroleum reservoirs for enhanced oil recovery (EOR) is hindered by multiple practical problems: availability of the CO2 sources, logistics of the delivery offshore, corrosion resistivity of the installations, and other. Previous studies of CO2 EOR for the reservoirs of the North Sea region, including core-flooding experiments and reservoir simulations, indicate that the deployment of CO2-EOR can significantly enhance the recovery of hydrocarbons. However, CO2 must be generated from anthropogenic sources, which affects the feasibility of the projects.
The current study evaluates the potential of a CO2-EOR project under the conditions of a specific petroleum reservoir of the Danish sector North Sea. Geological characteristics of the reservoir and the detailed oil properties lie in the ground of the study. The minimum miscibility pressures between CO2 and the reservoir oil are evaluated with the help of the in-house software (SPECS 5.70) and the commercial reservoir simulator (ECLIPSE 300). The results are verified in the slimtube simulations. The effect of the different oil characterizations and its lumping into the different numbers of components is investigated. The oil is found to be miscible with the carbon dioxide under reservoir conditions.
Several injection scenarios have been tested on the 2-D and 3-D reservoir models. Waterflooding was compared to injection of carbon dioxide, as well as water-alternate gas injection. An optimal scenario with regard to water-gas ratio under WAG was selected for further studies.
Finally, a cash flow model by Monte Carlo simulations and a sensitivity analysis on the impact of oil and CO2 price and discount rate, certify the feasibility and attractiveness of a CO2-EOR project in the West Flank of the Dan field.
With a suppressed hydrocarbon sector over the past few years, operators, service providers and ancillary companies alike have been strongly challenged to collaborate, where feasible, on field development solutions which offer greater economies of scale and efficiency by reducing operational time and cost. This paper details the evolution of the Harrier field development plan (FDP) in the context of innovation within completion and stimulation treatment design which has successfully created value for this North Sea gas operator.
Originally, the project plan comprised of two development wells, each accessing separate chalk gas reservoirs - Ekofisk and Tor which were approved by the UK Oil and Gas Authority in 2012 under the Stella and Harrier FDP, with an estimated development cost of USD 250 million. During the conceptual phase, the project economics were not attractive even in a high oil price environment. Services providers were then invited to provide alternative solutions to significantly enhance the investment appeal of this opportunity with the aim of reducing capital and operating expenditure while enhancing both field recovery and accelerated production. One such provider was successful with the proposition of a revolutionary contraction of the FDP with a unique design concept of a single well development terminating in a dual lateral with each leg targeting a separate reservoir in which fourteen acid stimulation stages per leg were planned to greatly enhance productivity. After several months of intensive collaboration, the optimized well design was completed and the project was sanctioned with field development cost reduced by a full 50%.
The paper provides an overview of the stimulation design, based on the reservoir challenges encountered and the progression of the completion design explored, into its final fit for purpose realisation. Results in relation to achievement of well objectives, service delivery, change management during the execution phase and most significantly overall well performance are also provided.
The objective of this paper is not only to demonstrate the value created to the field operator, but also to illustrate how planning and developing a unique solution was strongly influenced by a cost sensitive environment for efficiencies gained, with regards to risk management and mitigation, along with contingency planning. Furthermore, through a multi-segment integrated approach experience, numerous lessons learnt and best practices were harnessed for use when venturing on similar projects championing technical innovation under economic and resource constraints.
This paper discusses installation of the longest high-performance (HP) and rotating 11-3/4" expandable liner on the Elgin field in the Central-North Sea sector of the UK that enabled isolating weak layers in the overburden formations on EIE well, providing sufficient mud weight window to permit drilling high pressure and gas bearing zones. The planning and execution of this record presented challenges beyond those encountered in standard well conditions due to narrow mud weight window (NMWW) and critical requirement of zonal isolation.
EIE well was the third of the 2015-2017 infill campaign on Elgin field. The well faced major challenges in the 12-1/2" section due to the NMWW which triggered the deployment of the contingent well architecture with HP 11-3/4" expandable liner. This critical requirement of zonal isolation significantly impacted the preparation and risk assessment of expandable liner operations. A new expansion assembly design was implemented to allow rotation of the 11-3/4" size system to improve the cement job quality. Moreover, all contingency procedures were significantly modified to ensure that the objective of the specific well constraints were considered.
After under-reaming while drilling 12-1/4" × 14" section down to planned depth, 860m of 11-3/4" liner was run with no open hole problems. This liner was successfully rotated at bottom prior to pumping cement and fully expanded without incident. The system was successfully pressure tested prior to drill-out of the plugs and the shoe assembly was drilled with no issues.
Running of an 860m HP 11-3/4" expandable liner and rotating shoe assembly on EIE well is a record (longest HP string run before was 360m) and considered as a remarkable achievement. However, liner objectives were not fully met and cement squeeze below the shoe had to be performed. Post-job investigation highlighted issues related to dart selection and related cement over-displacement, limited contingences in case of expansion pressure loss, and the ability to pull the liner to surface in a NMWW. These issues remain to be solved for optimisation of future deployments.
This paper provides information on the design and operational aspects that should be considered for expandable liner operations on complex wells with NMWW. Understanding advantages and limitations of the system will open up opportunities to improve the technology and help to reduce operational risk.
Aamodt, G. (ConocoPhillips Skandinavia AS) | Abbas, S. (ConocoPhillips Co) | Arghir, D. V. (ConocoPhillips Skandinavia AS) | Frazer, L. C. (ConocoPhillips Co) | Mueller, D. T. (ConocoPhillips Co) | Pettersen, P. (ConocoPhillips Skandinavia AS) | Prosvirnov, M. (ConocoPhillips Skandinavia AS) | Smith, D. D. (ConocoPhillips Co) | Jespersen, T. (Halliburton Co.) | Mebratu, A. A. (Halliburton Co.)
This paper discusses a field case review of the processes used to identify, characterize, design and execute a solution for a waterflood conformance problem in the Ekofisk Field that developed in late 2012. The Ekofisk Field is a highly-fractured Maastrichtian chalk reservoir located in the Norwegian sector of the North Sea. Large scale water injection in the field began in 1987 and overall the field has responded well to waterflood operations. However, fault reactivation coupled with extensive natural fractures and rock dissolution has resulted in some challenging conformance issues. In late 2014, a solution was executed to control this problem. Details of the diagnostic efforts and how this data was used to identify, characterize and mitigate an injector/producer connection through a void space conduit (VSC) will be outlined and discussed. These diagnostics include pressure transient analysis (PTA), interwell tracers, injection profiles, seismic mapping, fluid rate analysis, fluid composition and temperature monitoring. The importance of this data analysis is the key element necessary to select an effective solution.
The selected approach involved pumping a large tapered nitrified cement treatment into the offending injector, which is believed to be the single largest nitrified cement operation ever pumped within the oil industry. Because of extremely rapid communication with an offset producer, a protective gel was used to reduce the risk of cement entry into that producer. A brief review of alternative mitigation options and the reasons for selecting the nitrified cement treatment will be discussed. Additionally, a complete review of the shutoff technique, product, damage mitigation strategy, and complications associated with timing and coordination in an offshore environment will also be discussed. Finally, a summary of lessons learned, job execution observations, post-treatment performance results over the past three years, and forward plans will be presented. Based on these results it is believed that there are a number of opportunities to add strong value through conformance engineering.