Cement holds the most critical role for providing long-term zonal isolation for permanent abandonment phase. The loss of cement integrity is undesirable as it may threaten the surrounding environment and safety on the surface. The quality of cured cement is commonly associated with the properties of cement material and cement placement in the wellbore. However, there are still limited investigations that link these factors specifically to the sealing ability of cement plug, especially with the lack of proper equipment in the past.
In the present work, a small-scale laboratory setup has been constructed to test the sealing performance of a cement plug. The cement plug is contained inside a test cell, connected to a pressurizing system and placed inside a heating cabinet. Consequently, the test can be simulated at downhole conditions in a controlled manner. By using this setup, it is possible to monitor the minimum pressure required for the plug to fail and the gas leak rate.
Two different cement systems, neat- and silica-cement, were prepared as plugging materials. Both cement systems are placed inside pipes with three different levels of surface roughness and then tested. Results show that the inner surface roughness of the pipes affects cement plug sealing significantly, and the effect is independent of the type of cement systems. Plugs placed inside a very-rough pipe significantly reduce the gas leak rate. Our results also show that an immediate gas leak occurs in all samples from leak paths formed at the cement/steel interface.
The most important contributer to Improved Oil Recovery (IOR) on mature fields is drilling of infill wells. Managed Pressure Drilling (MPD) and Continuous Circulation System (CCS) techniques can be used for improved control of bottomhole pressure when drilling wells in depleted fields with narrow pressure windows, but rig heave is a challenge when drilling from floating drilling units. Rig heave, caused by sea waves, induces pressure oscillations downhole that may exceed the operational pressure window. These oscillations are called "surge & swab" and occur both during tripping in and out of hole as well as during drill pipe connections, when the topside heave compensation system used during drilling is disabled because the drill pipe is put in slips. Downhole choking was introduced as a method to reduce downhole pressure oscillations induced by the rig heave and the concept was tested in laboratory scale and using computer simulations (
This paper gives an overview of the surge & swab simulator, describing its capabilities and limitations. Data from drilling of a North Sea well is then used to validate the simulations made using the software. The well, used as example in this paper, was drilled conventionally from a floating rig. The downhole pressure variations recorded during three different drill pipe connections are compared with simulated downhole pressure. The simulations are based on the recorded rig heave as well as the actual drilling fluid, well design and drill pipe data. Results show that there is a good correlation between simulated and actual measured downhole pressure. The surge & swab simulation software is then used to simulate the same drilling pipe connections using three different techniques and combinations of techniques utilized for improved downhole pressure control: (1) Managed Pressure Drilling (MPD) (2) Managed Pressure Drilling combined with Continuous Circulation System (CCS) and (3) MPD combined with CCS and a downhole choke. Results show that rig heave-induced downhole pressure variations are reduced to a level which is considered acceptable for drilling a well with narrow pressure window for the last two cases, while utilization of backpressure MPD alone is not sufficient. The combination of MPD and CCS reduced surge & swab for two out of three connections. For the third and deepest connection, the surge & swab increased. The largest reduction in significant downhole pressure variations (43-68 % vs. conventional drilling for the three connections) occurs when MPD and CCS are combined with downhole choking.
Future work will consist of further developing the surge & swab simulator so that it will be possible to utilize it in well planning and as real-time decision support during drilling operations. The simulator will also be developed to include possibility of simulating various well completion operations such as running casings and liners. A prototype of the downhole choke is currently being tested at the mud loop of the Ullrigg test rig facility in Stavanger, Norway, and the next development phase consists of designing and building a complete downhole tool for testing in a well.
The annular casing cement is an important part of the well barrier throughout the life cycle of a well. With the increasing number of subsea plug and abandonment (P&A) operations, increased attention is now given to annular cement evaluation and the ability to prove adequate zonal isolation. Today, cement evaluation by logging is performed almost exclusively using acoustic logging tools. One of the concerns when it comes to cement integrity is the frequently occurring micro-annulus at the casing-cement interface. Yet, a typical cement evaluation tool may lack of accuracy on its evaluation. Hence, a novel concept for the evaluation of casing-cement micro-annulus has been proposed.
This paper describes a mechanical-based approach for cement evaluation – the Annulus Verification Tool (AVT). The AVT applies a radial force on the casing inner wall that yields an ovalization of the cross-section, while recording the radial displacement of the casing. A prototype of the AVT has been constructed along with an experimental setup to allow for initial testing of the tool. This comprises the construction of full-scale diameter samples representing a typical 9 5/8-in. production casing cement job, with the possibility to generate a uniform micro-annulus of a known size at the casing-cement interface.
The tests performed have shown that the AVT is able to differentiate a casing supported by an annular cement sheath from a free pipe, due to the stiffness contrast. By measuring the casing radial displacement with high resolution, the results have shown that a microannulus can be detected and its size quantified with good accuracy. Experimental tests performed with tool eccentricity and tilting has shown that the AVT should be kept centralized to achieve accurate quantification of the microannulus size.
The AVT module is meant to complement the acoustic tool sting used today, and to improve evaluation of the cement sheath's sealing capability, especially in cases where a micro-annulus is detected or suspected. If an existing microannulus is suspected, the AVT logging response may confirm its occurrence, quantify its size and aid the planning of remedial operations to restore the annular barrier.
The present paper will explore an alternative subsea system configuration where it is possible to install dedicated equipment for each well (or group of wells) depending on its particular needs (e.g. boosting, separation, metering). This could allow achieving efficient and optimal management of the integrated system over the entire life of the field. Additionally, it opens for opportunities to optimize the operation of equipment and the utilization of resources. To test the concept, a field life study was performed on a conventional subsea oil field using a commercial software for modeling of production systems. The reservoirs were represented using a material balance model, and well rates are calculated considering the pressure drop and pressure increase (boosting) along the production system. Three cases were simulated and compared in terms of their cumulative oil production and power consumption when subsea processing is required. Case 1) standard configuration of pipeline-riser system without subsea processing unit, case 2) including a single subsea booster in the original network system, and case 3) including a modular assembly with boosting capabilities to individual wells. From all the evaluated cases, Case 3 showed the highest cumulative oil production at the end of field life. Two production strategies were tested for case 3: System demand (boosting units starting up at different times according to wells requirement) and simultaneous running mode (all boosting units starting up simultaneously). The different production strategies influence the potential for system improvement in terms of the process efficiency, production rate, and power demand.
Zhao, Dapeng (Norwegian University of Science and Technology and SINTEF) | Hovda, Sigve (Norwegian University of Science and Technology) | Sangesland, Sigbjørn (Norwegian University of Science and Technology)
Dapeng Zhao, Norwegian University of Science and Technology and SINTEF, and Sigve Hovda and Sigbjørn Sangesland, Norwegian University of Science and Technology Summary Most drill-collar-connection failures are attributed to cumulative fatigue caused by bending vibration. An important class of bending vibration is whirl, which is formed by the eccentricity of the rotational drill collar. A two-degree-of-freedom nonlinear lumped-mass model is used to represent the drill collar in whirl. Unlike other studies, the stick/slip vibration causing fluctuation of rotary speed is taken into account. In this lumped-element model, the contact forces obey the Hertzian contact law, which leads to lateral bounce of the drill collar and affects the borehole wall chaotically. The modified Karnopp friction model is adopted to simulate the stick/slip rotary vibration of the bottomhole assembly (BHA). On the basis of the time-domain responses of whirl, the continuous-bending-stress history is broken down into individual stress ranges with an associated number of stress cycles using the rainflow-counting method. The cumulative fatigue damage is estimated using Miner's rule.
Moser, Tijmen Jan (MGS) | Arntsen, Borge (Norwegian University of Science and Technology) | Johansen, Ståle (Norwegian University of Science and Technology) | Raknes, Espen (Norwegian University of Science and Technology) | Sangesland, Sigbjørn (Norwegian University of Science and Technology)
Diffractions from boreholes can be made visible using surface seismic data, subject to certain favorable conditions. This makes diffraction processing and imaging a more natural complement to the Surface Seismic monitoring While Drilling (SSWD) method than traditional reflection processing, which suffers from limitations in illumination and resolution. We discuss the SSWD method in combination with diffraction imaging and demonstrate its potential on a field data set.
Presentation Date: Wednesday, October 19, 2016
Start Time: 8:50:00 AM
Presentation Type: ORAL
In order to predict downhole surge and swab pressure variation due to movement of the drill pipe, the Stribeck friction model has been outlined to analysis the friction induced stick slip motion in inclined bore holes. This model describes the axial stick slip motion of the drill string through four regimes of contact including sticking, boundary lubrication, partial fluid lubrication and full lubrication. The results from the single degree of freedom (dof) model are compared with the Coulomb friction model. The results indicate significant increase in peak velocity of the lower part of the drill string and Bottom Hole Assembly (BHA) compared to the velocity of the drillstring at surface, i.e., during drill pipe connection using a MODU (Mobile Offshore Drilling Unit). Simulations also show that the wave form of the downhole drill string motion will be different compared to the surface motion due to the stick phase caused by variation of contact force between the drillstring and the borehole in the curved section of the bore hole. In long high deviated boreholes, the movement of the BHA and the corresponding surge and swab pressure during drill pipe connection will be low or negligible due to high drag force and elasticity of the drill string.
This paper describes a new drilling riser concept and drilling method that will remove some of the well control challenges presently encountered and provide improved well control procedures, when handling deepwater kicks and deep formation gas flow into a well being drilled. The new system will also allow for longer hole sections to be drilled in deepwater, thus reducing the number of casing strings required in the well and reduce the chances of hydrate plugs forming at seabed.
The main element in the system is based on using a smaller size (14"-12.5" ID) high pressure drilling riser with a split BOP between surface and subsea, a subsea mud pump connected to the high pressure drilling riser, taking returns from a lower level in the riser. The mud level in the riser is dropped down to a level considerably below sea level to create a mud/air interface ("mud cap") that can be continuously adjusted up or down by the mud-lift pumping system. As a consequence, the bottom hole hydrostatic pressure will be controlled. One of the main purposes of this system is to mitigate the inherent problems with a conventional 21" marine drilling riser during well control scenarios in deepwater operations. It will adjust the bottom hole pressure accordingly and compensate for frictional pressures due to circulation.