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.
Shell in the UK has a vast network of more than 200 pipelines & umbilicals covering some 3000 kilometres. Historically, Shell has executed Side Scan Sonar Surveys along these pipelines using a Remotely Operated Towed Vehicle and subsequently followed up with ROV based surveys & inspections. However, in 2018, the respective Geomatics & Subsea Maintenance / Pipelines Departments decided to take advantage of new & emerging innovative technologies and compiled a minimal technical scope & tender document to tap into the latest that the market could offer. Consequently, Shell UK awarded DeepOcean (Norway) with a contract for their "Fast Digital Imaging Service" and embarked on a 45 day survey campaign. In 2019, the same subsea inspection project will be executed once again and the lessons learned ought to inspire and excite many different disciplines and communities, both internally within Shell and externally e.g OGA - Oil & Gas Authority & other valued stakeholders. The paper highlights the key technologies that were deployed and how the new deliverables & business insights take us down the road to Digitalisation including scope for future Machine Learning & Automation processes. Challenges arising from the acquisition and managing the associated data sets shall also be discussed. The speaker will spark dialogue at the end by asking the respective communities how robotics and artificial intelligence will change the industry landscape?
This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage. This paper discusses the successful application of managed-pressure drilling (MPD) in the basin with reduction in risks and well costs. This paper discusses how managed-pressure-drilling (MPD) technology led to cost savings in two wells drilled in the Hai Thach gas field offshore southern Vietnam. This paper describes how a technique known as applied-surface-backpressure managed-pressure drilling (ASBP-MPD) can alleviate the limitations of conventional deepwater well control. The complete paper describes a recent directional coiled-tubing drilling (DCTD) job completed for an independent operator in the Appalachian Basin.
We must concentrate our paper selection on technology and operating methods that make HP/HT drilling operations faster, safer, and more cost-efficient. If above-threshold drilling costs shelve a project, the project will not fly. And without projects, HP/HT know-how and equipment quickly disappears. This paper discusses the successful application of managed-pressure drilling (MPD) in the basin with reduction in risks and well costs. This paper discusses how managed-pressure-drilling (MPD) technology led to cost savings in two wells drilled in the Hai Thach gas field offshore southern Vietnam.
I am encouraged that we, as an industy, continue to refine and tweak our practices to solve zonal-isolation and cementing challenges in every well environment in which we work. As cementing techniques are improved, so, too, are the cement-evaluation methods and work flows. This paper demonstrates a new way to create gas-tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed. This paper discusses shale creep and other shale-deformation mechanisms and how an understanding of these can be used to activate shale that has not contacted the casing yet to form a well barrier. Well RXY is located in Cairn’s Ravva offshore field in the Krishna-Godavari Basin in India.
Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
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.
Salehabadi, Manoochehr (Shell UK Exploration & Production) | Susanto, Indriaty (Shell UK Exploration & Production) | Prin, Cindy (Shell UK Exploration & Production) | Freeman, Christopher (Shell UK Exploration & Production) | Laird, Rebecca (Shell UK Exploration & Production) | Gernnaro, Sergio De (Shell UK Exploration & Production) | Forsyth, Gatsbyd (Shell UK Exploration & Production) | Doornhof, Dirk (Nederlandse Aardolie Maatschappij B.V.)
Strong reservoir pressure depletion after years of production in a high pressure, high temperature (HP/HT) oil field in the UK Central North Sea led to reservoir compaction and stress changes in the overburden, which consequently had an impact on the fracture gradient profile. The understanding of the current fracture gradient is essential as it is one of the two key process safety inputs for further drilling or abandonment design. Besides ensuring hydrocarbons are kept within the reservoir/subsurface by assessing the caprock integrity, the ability to accurately estimate the fracture gradient range can potentially provide significant savings in the design and concept select phases, especially for HP/HT fields as most investments are very capital intensive. Stress changes in the overburden rock due to reservoir compaction ("stress arching effect") can be observed from the Time Lapse (4D) seismic data as a velocity slow down due to overburden stretching/ expansion. An integrated study was conducted by developing a 3D geomechanical model and coupling with 4D seismic data to assess the current fracture gradient in the overburden, specifically in the caprock. The results of this study show that overburden weakening is strongest at the top of the reservoir and extends up to mid overburden. The lateral extent of the weakening is confined by the area of the depleted reservoir. In this paper, we demonstrate the benefits of understanding the current fracture gradient, both for abandonment design by optimising the number of cement plug isolations and their location as well as for assessing the caprock integrity during long term abandonment.
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.
Kan, Amy T. (Rice University) | Dai, Joey (Zhaoyi) (Rice University) | Deng, Guannan (Rice University) | Harouaka, Khadouja (Rice University) | Lu, Yi-Tseng (Rice University) | Wang, Xin (Rice University) | Zhao, Yue (Rice University) | Tomson, Mason B. (Rice University)
Numerous saturation indices and computer algorithms have been developed to determine whether, when, and where scale will form. However, scale prediction can still be challenging because the predictions from different models often differ significantly at extreme conditions. Furthermore, there is a great need to accurately interpret the partitioning of water (H2O), carbon dioxide (CO2), and hydrogen sulfide (H2S) between different phases, as well as the speciations of CO2 and H2S. This paper summarizes current developments in the equation-of-state (EOS) and Pitzer models to accurately model the partitioning of H2O, CO2, and H2S in hydrocarbon/aqueous phases and the aqueous ion activities at ultrahigh-temperature, ultrahigh-pressure, and mixed-electrolytes conditions. The equations derived from the Pitzer ion-interaction theory have been parameterized by regression of more than 10,000 experimental data from publications over the last 170-plus years using a genetic algorithm on the supercomputer DAVinCI at Rice University. With this new model, the 95% confidence intervals of the estimation errors for solution density are within 4×10–4 g/cm3. The solubility predictions of CO2 and H2S are accurate to within 4%. The saturation-index (SI) mean values for calcite (CaCO3), barite (BaSO4), gypsum (CaSO4·2H2O), anhydrite (CaSO4), and celestite (SrSO4) are accurate to within ±0.1—and for halite the values are within ±0.01—most of which are within experimental uncertainties. This model accurately defines the pH value of the production tubing at various temperature and pressure regimes and the risk of H2S exposure and corrosion. Furthermore, our model is able to predict the density of soluble chloride and sulfate SO2–4 salt solutions within ±0.1% relative error. The ability to accurately predict the density of a given solution at temperature and pressure allows one to deduce when freshwater breakthrough will occur. In addition, accurate predictions can only be reliable with accurate data input. The need to improve the accuracy of scale prediction with quality data will also be discussed.