The last several years has seen an increasing trend toward more depleted reservoirs and more challenging wells with tighter mudweight windows. Managed Pressure Drilling has been employed in these challenging well conditions, however industry take up has been slow for a number of reasons including technical, economic and deployment related. Those wells that have utilized Managed Pressure Drilling have tended to focus on the drilling related aspects of well construction. However, other areas of well construction such as casing and liner running and cementing and completion installation are equally and in some cases even more technically challenging. One area that has potentially hindered the uptake of Managed Pressure Drilling is that in general, and in particular in the well construction operations outside of on bottom drilling there has been no access to real-time downhole data. In particular this is related to real-time pressure data. Whilst cementing, displacing or completing then multiple fluid types and densities may be circulating both inside and outside the drillpipe, leading to significant challenges in simulations and models derived from surface data. To overcome this a new acoustic telemetry and measurement network is being deployed in depleted reservoir and managed pressure drilling operations to provide real-time downhole and along string measurements of pressures, temperatures and weights. Real-time data case histories will be shown from the Gulf of Mexico and the North Sea illustrating how this is being used to drive real-time decisions during drilling, cementing and completion installation operations in tight margin windows, depleted reservoir conditions and under managed pressure drilling operations.
An exploratory well with a narrow drilling margin can be realized successfully by use of a customized design concept. Such a concept may not follow standard procedures strictly as ordinarily defined but still can fulfill the guidelines and concepts behind conventional approaches. To apply such a customized concept, a multidisciplinary team was created to design the well through all the possible expected scenarios. An integrated assessment was prepared, evaluating how real-time monitoring could mitigate the operating risk of the exploration activity. The operator’s guidelines used for standard parameters such as kick tolerance and choke margin were reviewed and reinterpreted for this specific application, because the introduction of new technologies could allow different design factors to control the bottomhole pressure (BHP) without affecting the margin of risk.
This paper introduces an active wellbore sealing system for use in Managed Pressure Drilling (MPD) incorporating a wellbore seal condition monitoring system. The paper will discuss how finite element analysis which has previously been validated with full scale testing can be expanded to develop the condition monitoring system.
In contrast to a passive rotating control device, an active MPD wellbore sealing system requires hydraulic pressure to engage a sealing element and form a wellbore seal. The paper will investigate the relationship between wellbore sealing pressure and hydraulic fluid parameters using the results of finite element analysis on a sealing technology which has been previously operated offshore in addition to extensive full-scale testing in a lab environment.
The paper will show how the required hydraulic fluid requirements to form a wellbore seal change over time due to sealing element wear. The information can be used to predict the remaining life of the existing sealing element as well as proactively alarm the driller of the need to replace a seal sleeve due to a sudden deviation from expected behavior. The implementation of a real-time, condition monitoring system for the MPD wellbore seal is intended to increase the rig's confidence toward using MPD for challenging hole sections as well as circulating out small influxes from the well without closing the SSBOP, further reducing the risk of stuck pipe events.
The active MPD wellbore sealing system is a non-rotating, offshore wellbore annular sealing device which is integrated into the riser. It contains a seal of elastomeric composition which seals against drill pipe during all tripping and drilling operations. As the seal wears, the hydraulic closing fluid requirement to maintain an annular seal changes, which indicates the amount of seal material remaining.
AbstractMPD enables drillers to navigate through narrow drilling windows to reach designed target depths. After a hole section is drilled, pressure management is still required to pull drill strings out and run and cement liners. Conventional cementing programs and procedures may not be practical for a challenging hole section that has been drilled by MPD. Elaborate wellbore pressure management is required to ensure safe and efficient cementing operations. The same closed loop circulation system utilized for drilling is used to manage the wellbore pressure during cement operations. The technique of pressure management during liner cement jobs was utilized repeatedly by a major client in one of the most challenging HPHT campaigns in the North Sea. This paper provides an insight into the technique as well as information on the procedures, challenges and lessons learned pertinent to these operations. Various cases studies describing the setup, planning and execution of operations, simulation vs measured data will be compared.Drilling wells in complex environments with century-old technology is difficult at best and unsafe at worst. From drilling through narrow pore-pressure/fracture-pressure gradient windows to mitigating kicks and differential sticking, managed pressure drilling (MPD) succeeds when conventional techniques are likely to fail. MPD entails the use of specialized equipment to control wellbore pressure profiles more precisely than is possible with conventional drilling methods. MPD enables drillers to navigate through narrow drilling windows to reach designed target depths. After a hole section is drilled, pressure management is still required to pull drill strings out and run and cement liners. Conventional cementing programs and procedures may not be practical for a challenging hole section that has been drilled by MPD. Elaborate wellbore pressure management is required to ensure safe and efficient cementing operations. The same closed loop circulation system utilized for drilling is used to manage the wellbore pressure during cement operations. A case study describing the setup, planning and execution of operations, and simulation is presented in this paper.
With more wells drilled into hydrocarbon bearing formations, operators are forced to drill into challenging plays with narrow pressure margins. Successful drilling in depleted zones with isolated, high-pressured fractures is difficult and requires managed pressure drilling (MPD). Once the well is drilled, the operator should achieve zonal isolation by pumping cement across the zones of concern without inducing lost circulation or gains. Managed pressure cementing (MPC) pumps cement in a hydrostatically underbalanced environment with pressure applied at surface using an automated choke system (ACS) to maintain a target equivalent circulating density (ECD) between the highest pore pressure (PP) and the lowest fracture gradient (FG) of the well. Communication between cementing operations and MPD software allows automatic system adjustment without manual input. The MPD hydraulic model tracks multiple fluids with different densities, rates, and rheological properties throughout the wellbore. A rig pump diverter (RPD) allows for constant bottomhole pressure (BHP) by manipulating the surface choke pressure if unplanned shutdowns occur. Successful MPC operations have been conducted using the ACS in the Paradox Basin with narrow pressure windows and in the Piceance Basin with high reservoir pressure zones. The nature of cement operations can be unpredictable, but through the automatic managed pressure cementing (AMPC) process, a target ECD can be identified and constant BHP maintained to design and deliver dependable barriers tailored to minimize risk and maximize production.
Riphean anisotropic cavernous-fissured carbonate reservoirs of oilfield at East Siberia area – one of the most problematic objects of oil and gas production described in this article. Here is discussed geological substantiation and first result of new technology involving in drilling of Riphean carbonate reservoirs with "Controlled pressure technology" by recovery wells with horizontal bottom at the oil-gas condensate field in Evenki Region. Comparison results of conventional drilling and "MPD" (Managed Pressure Drilling) technology.
Riphean reservoirs drilling process could be provided in two options.
The first one – horizontal conventional drilling. As far as the bit penetrates into the reservoir we are seeing SPP (Stand Pipe Pressure) decrease which means we have total lost circulation. There was only one means for resolving this problem – using LCM (Lost Circulation Material). Due to complicated geology and high parameter of gas factor in Riphean reservoirs (losses while circulation/ gains while static), LCM was insufficient solution.
The second is to perform drilling process using MPD (Managed Pressure Drilling) technology. We have the advantage using lower mud weight compared with conventional drilling. MPD technology corresponds with geological conditions of Riphean reservoirs and can be more profitable in future production from these wells.
MPD technology with closed loop circulation system showed that we can "manage" BHP (Bottom Hole Pressure) and it really works in temperature conditions of 45 Celsius below zero in Evenki Region (East Siberia). In practice we have seen, that it was possible to achieve more gentle management of BHP than with conventional drilling using LCM. Also with "MPD" system in this oilfield we were able to drill the first ERD (Extended Reach Drilling) well. However, even with such extended horizontal section (1000 meters), a significant reduction of losses was achieved without using LCM. Total results of MPD technology we will see after DST (Drill Stem Test) of drilled wells.
New technology showed that it was a right choice to use close loop system and MPD. Also for drilling new wells in this Riphean carbonate reservoirs of this oilfield area we will use this experience. Best way to reduce catastrophic losses in abnormally low pressure reservoir conditions is reduce and control the ECD and details how to achieve it we have considered in this article.
The results: Reduced interval construction time. From 31 days to 24 days. Reduced fluid loss during drilling. From 2000 m3 to 1200 m3. Improved the operational safety by closing the loop and real time early kick and loss detection.
Reduced interval construction time. From 31 days to 24 days.
Reduced fluid loss during drilling. From 2000 m3 to 1200 m3.
Improved the operational safety by closing the loop and real time early kick and loss detection.
The Canadian SAGD (Steam Assisted Gravity Drainage) industry continues to grow with more wells being drilled in Alberta that cannot be mined. Drilling issues addressing low reservoir pressure, tight well spacing, highly pressurized steam injection, cap rock integrity and tight drilling windows are currently some of the challenges being faced today.
As industry looks for a way to improve and mitigate both drilling and environmental issues, this paper presents a drilling solution on applying an automated MPD (Managed Pressure Drilling) technique proven to identify and react to the actual wellbore pressures, detect and control gain and losses within liters, while still having the ability to maintain a CBHP (Constant Bottomhole Pressure) while drilling through tight windows.
This document demonstrates the successful application of advanced automated MPD technologies on Suncor’s Dover well close to Fort McMuarry, Alberta and will also elaborate on recommended operational procedures, equipment set up and process flow diagrams along with the analyzed graphical data.
The results demonstrated a successful re-drill of a producer well within an over pressured reservoir induced by steam injection by using near water density mud weights, minimizing mud losses, preventing any steam or bitumen intrusion by monitoring return density to surface while maintaining bottom hole pressure within a narrow operating window.