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.
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.
The negative impacts of high water cut in mature fields are well known within the oil & gas industry. Water production preventive & mitigative measures are well established and documented: Wireline or coil tubing conveyed diagnostic and work-over operation(s) is one of such common preventive measures. This paper, through a series of integrated case studies will highlight the best practices for wireline conveyed logging and work-overs with one common goal, i.e. to achieve the water production to a minimum acceptable level in deviated high water cut wells.
The prolific XYZ field is located in the Northern North Sea and it produces oil from Jurassic Brent Group. Oil production from the XYZ reservoir started in early 1978, with 43 producing wells and 15 water injection wells targeting the Rannoch, Etive, Ness and Tarbert sands. Oil and gas production peaked in 1982 and since then production has steadily declined for this field. The increasing water cut in the wells of this field is presenting a challenge for the operating companies.
Production profiling using advanced Production Logging data, casing/tubing integrity check using Multi-Finger Caliper data and saturation monitoring using cased-hole Reservoir Saturation data was done in these wells to ascertain the water producing zones and do the subsequent well intervention, if required. A strategic diagnostic test was designed to precisely evaluate the flow profile using advance production logging tool consisting of 5 mini-spinners & 6 sets of each electrical and optical probes; Real-time data assessment and analysis was done for different flowing rate surveys to validate the findings. Additionally, casing condition was evaluated using Multi-Finger Caliper to decide Plug or Straddle setting depths. Also, new hydrocarbon bearing zones were identified based on cased-hole saturation tool results. The analysis results boosted the cumulative oil production.
This study demonstrates the importance of making real time interpretation decisions at the wellsite and the benefit of developing a good working relationship between wellsite engineers and onshore technical support. The results of this work led to the unequivocal determination of major oil and water producing zones in deviated high water cut (95%+) wellbores which further helped in taking workover decisions to carry out water shut off, utilizing either plug or straddle technology. The findings of caliper data determined the appropriate plug or straddle setting depths. The results were compared and confirmed with the nearby well dynamic pressures and production data.
The technical approach and processes applied to wells of XYZ field is a valuable example guide to decide water shut off zones and technique of similar plays. This study consists of three integrated case studies from a mature field where water shut-off zones and technologies were decided based on the findings of production logging and well integrity data. Also, re-perforation jobs were performed based on the cased-hole reservoir saturation data results. These strategic workover operations ultimately led to significant increase in hydrocarbon production.
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.
Islam, M. S. (Dhofar University in Oman and Fault Analysis Group, UCD School of Earth Sciences, University College Dublin in Ireland) | Manzocchi, T. (Fault Analysis Group and Irish Centre for Research in Applied Geosciences, UCD School of Earth Sciences, University College Dublin)
Most petroleum reservoirs contain faults, and a major technical challenge in full-field flow simulation is to represent the effects of 3D fault zone structure within the 2D fault surface represented in the industry standard commercial simulator. Geometrical upscaling (GU) is sometimes performed to include these fault zones implicitly in the upscaled model, and in this study, a comparison is made of the accuracy and flexibility of different geometrical upscaling methods. The existing template-based geometrical upscaling (TBGU) method is compared to a new flow-based geometrical upscaling (FBGU) method. In both methods, the faults are represented in the upscaled flow simulation model implicitly as neighbor and non-neighbor cell-to-cell connection transmissibilities, which are determined from 3D fault zone structures, but these transmissibilities are calculated in very different ways. Both approaches require a high-resolution flow simulation model (referred as truth model in this paper) containing complex 3D sub-seismic fault zone structure explicitly, which is then upscaled using the two methods to take into account the influences of the fault zone geometry as across-fault and along-fault flow. The accuracy of the upscaling methods is examined by comparing the flow behavior of the high-resolution flow simulation model with that of model versions upscaled in the two different ways. Individual well performance for the high-resolution truth and the upscaled models reveal significant differences between the two methods, and indicate that the flowbased geometrical upscaling technique is a more accurate means of including structurally complex fault zones into low-resolution upscaled flow simulation model.
The objective is to enable a full simulation lifecycle of multi-billion cell reservoir models for gigantic Middle Eastern reservoirs utilizing parallel hardware. Debugging, building and developing models with this resolution is not possible without seamlessly changing the scale of the reservoir model and applying a portfolio of boundary conditions to fit the current workflow.
Throughout the lifecycle of the full-field reservoir model a variety of simulations are needed, including small, single and multiple well sensitivity studies (O(108) cells), regional models (O(107) cells), and ultimately full-field modeling (O(109) cells). It is crucial this can be achieved in a way to exploit the current hardware, with a minimum memory and computational overhead, and have a quick and seamless way to maintain the integrity of the full-field model, without the need for complex pre- and post-processing tools. This is achieved here by the definition of a compact stacked contour; this is cheap enough to be read by every processor in the current run, and by exploiting advanced parallel IO techniques; only the portion of the full-field grid to be simulated needs be imported to core memory. This definition easily lends itself as a natural way to apply boundary conditions to model aquifers, fluxes derived from larger models, and pressure boundary conditions.
The techniques described here will be demonstrated on a number of workflows. Firstly, in aquifer modelling, to exclude the large number of aquifer cells that often arises from simulating on a geological level model, and replace these cells with an analytical model. An external program takes the area of interest, and using the convex hull of the area of interest generates a stacked contour, which is subsequently used to define a Fetkovich aquifer. Secondly, a pressure boundary condition is applied to an area of interest within a full-field model to mimic the decline.
The definition of a stacked compact contour enables the large reservoir model to be analyzed at local, regional and full-field scale while maintaining the integrity of the full-field model. A variety of boundary conditions are applied to the stacked compact contour.
On the Vega gas condensate and oil field in the Norwegian North Sea, two high temperature, high pressure (HTHP) gas condensate wells on one subsea template in 370 m water depth were acid and scale inhibitor treated in order to improve productivity by acid scale removal and prevent future scaling. Significant amount of work was undertaken on design and qualification of the treatment fluids. In order to reduce operation time and increase efficiency, a novel one-time connection concept was utilized. During the operations, wells were kicked off after energizing with gas bullheaded from the neighbouring well. The treatment fluids were designed to reduce consequences for the host facility due to H2S generated during the operation - this required optimization after understanding of the H2S source as witnessed in prior treatments.
The new concept with one-time connection was successfully employed and allowed for three subsequent well treatments in a row, thus saving at least two days vessel operations time. The gas injection from the neighbouring well - the one not treated at the moment - allowed for an efficient start-up of the treated well without need for larger nitrogen injection which would have led to contamination and potentially to flaring due to off-spec gas. The introduction of a batch with pH neutralizer and H2S scavenger batch into the treatment design to be placed into the production pipeline reduced H2S liberation and production to the host facilities, thus limiting the operational stress on the platform. Productivity of well A1 showed an immediately significant increase after the operations, whereas productivity of well A2 required a longer clean-up than originally anticipated.
In Vietnam, there was a need of a lean surface casing due to restricted drift inside diameter (ID). The 2nd slot of the splitter conductor only have 13-1/2" ID max pass through. The practical option is to drill with 12-1/4" bit and open to 14-1/2" hole to set 11-3/4" casing OD. Similar reasoning for the intermediate hole that will require to under ream the hole from 10-5/8" bit to 12-1/4" hole and set 9-5/8" casing OD. Although these under reaming operations are commonly practiced, the technical limitations are still inefficient and compromising. Conventional reamers still have limited activation/deactivation cycle for operational flexibility and long rathole of the reamer to bit depth for casing shoe placement.
The long awaited technology is now available with the presence of intelligent reamers that have unlimited activation & deactivation cycles and can be placed directly above the rotary steerable system for shortest possible rathole. The setup is to combine two intelligent reamers in a single BHA. The 1st reamer placed strategically on top of the MWD & LWD tools while the 2nd reamer is directly above the rotary steerable system tool. As both reamers can be both activated and deactivated through downlinking, the reamer has to be activated simultaneously to control the risks associated with hole opening and LWD data acquisition. The 1st intelligent reamer will be activated first while drilling the section formation and the 2nd intelligent reamer will then be activated at section TD to ream and shorten the rathole. For the purpose of cleaning the hole effectively, both reamers can be deactivated to execute high flow and RPM without creating new cuttings from the reamer blades and avoid making a bigger hole at the low side.
This enabled shoe to shoe drilling while under reaming and achieving less than 10m rathole. These operational capabilities saved at least 50% of the section rig time compared to having a 2 trip system. Combination of reduced casing shoe rathole and open hole exposure mitigated the well bore instability risks and helps in managing mud weight for both hole section intervals. The unlimited activation cycle provided flexibility in operations particularly in dealing with hole cleaning and wiper trips. Plus, the intelligent reamer provides realtime reamer diameter which gives confidence on the drilled hole size for casing running preparation and decisions.
Intelligent reamers have unique tool features that differentiate from the rest of current industry technologies. This feature helps to eliminate the risk of under-reamer balling, which improve the rate of penetration. The success of the operation has spread throughout operators in Vietnam, and now the intelligent reamer is considered as a game changer application in drilling lean casing profiles.
The ‘Pseudo’ Dry Gas (PDG) subsea concept is being developed to dramatically improve the efficiency of subsea gas transportation by removing fluids at the earliest point of accumulation. The technology will increase the geographical reach from receiving gas terminals, allowing asset owners to prolong production life without the need for more expensive design solutions. This paper will provide an overview of the innovative technology, demonstrating that a 200 km plus tie back can be achieved, without compression.
Increasing the distance of subsea tie-backs increases the liquid inventory, with constraints on pipeline diameter for slug free flow. The PDG concept is based on a main gas line integrated with piggable gravity powered drain liquid removal unit and pumps (a smaller fluid line transports separated liquid). Multiple units are specified to drain liquids as they condense in the line, maintaining near dry service. Liquid free operation removes the constraint on pipeline diameter. Specification of a large diameter pipe (within installation limits) reduces backpressure on the wells, enhancing recovery. Minimum stable flow limits are removed, improving tail end recovery.
Current stranded gas development options (subsea compression, floating facilities, FLNG) generate a step change in costs which can make a project uneconomic. This is even more acute in mature and semi-mature basins where existing gas processing facilities / LNG terminals already exist offshore or onshore along with sunk costs from the exploration. A case study for a 185 km pseudo dry gas subsea tie-back to shore demonstrates the PDG concept feasibility. This result is used to argue that the PDG concept should be included in the suite of subsea processing options considered by Operators in early field development planning.
Recent developments of new ultra-deep logging-while-drilling (LWD) resistivity tools have increased usage for on-demand computational infrastructure. The tools are capable of providing much deeper determinations on formation geologies than conventional electromagnetic (EM) resistivity tools, allowing more accurate real-time wellbore adjustment and optimization. This technique efficiently explores reservoir insights for maximizing oil production; however, the time to process raw measurements into useful geological information is long owing to the complexity and large amount of data associated with the tools. The conventional computation platforms are not efficient enough for both real-time and post-well formation evaluations based on this tool's measurements. This paper introduces a high-performance computing (HPC) platform which provides flexibility among different deployment architectures and large-scale cloud infrastructure. This enables numerous computational resources to quickly process raw data and provide the information needed to successfully steer a well. The new HPC platform has 50% more efficiency compared to conventional parallelization methods, such as Open Multi-Processing (OpenMP), using same amount of CPUs. Furthermore, faster computation is achievable owing to the scalability of the HPC implementation as well as the flexibility of available assets in the cloud or on-premises environments, which are beneficial for applications with heavily computational requirements and short time constraints.