The successful cementation of top-hole sections of three development wells offshore Malaysia has been very challenging since from offset wells nearby the fracture pressure in this section was very low. The section was supported only by an overburden of 328 ft (100 m) of water and 492 ft (150 m) of soil. With such low support, the top-hole section had repeatedly hemorrhaged cement into the formation rather than getting good annular cement coverage to surface. As much as 130% more cement than should have been required was wasted in these efforts. In this study we review these case histories and describe how we overcame the given challenges by implementing an innovative spacer cement train.
During drilling the wells, the inadequate isolation had also allowed as much as 30 bbls/hr of drilling fluids to escape. Analysis suggested that a lighter-weight cement would reduce the pressure on the formation to levels the formation could support, enabling to fill the annulus with cement without losses. To minimize the losses into the thief zone and to bring up the lead slurry to the desired depth by reducing the equivalent circulating density (ECD) at the top-hole we engineered a stable lightweight cementing system which does not require extenders or lightweight spheres. With this approach we simplified logistics and operations but also brought the quality control of the cementing system to a higher level, since the potential separation between lightweight material and cement was not anymore of concern.
Laboratory testing was conducted to design this fit-for-purpose solution. This helped to eliminate the amount of synthetic products (such as beads) in their slurry, which greatly reduced their cost. At the same time, it provided better properties such as compressive strength development compared to the slurry that had been implemented on previous wells. A sealing spacer system was incorporated into the design to further prevent losses as an additional layer of assurance. As expected, the top-hole sections of the 3 wells were completed with no recorded losses. Cement coverage was confirmed throughout the annulus, and we did not have to pump 130% more cement than required, as we had to on previous wells.
Unlike previously cemented wells in the area with low frac gradient along the top-hole section, the three wells that used the innovative spacer cement train did not suffer subsequent drilling fluids losses because they were adequately isolated. The combined effect of the lightweight cementing system and the sealing spacer was a drastically reduced cement cost and a better ultimate isolation.
Liu, Xiaodong (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co.,Ltd.) | Xie, Binqiang (Yangtze University) | Gao, Yonghui (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co., Ltd.) | Gu, Huiling (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co., Ltd.) | Ma, Yongle (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co., Ltd.) | Zhang, Yong (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co., Ltd.) | Zhang, Ruxin (State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum-Beijing) | Li, Qingyang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
It brings severe challenges to drilling fluids when drilling high temperature deep well in environmentally sensitive sea area and facing strict environmental protection laws and regulation requirements meanwhile, the toxic value of drilling fluid must reach up the standard requirement of 30,000 mg/L.A new, environmentally safe water-based polymer system has been developed for drilling applications with temperatures resistance to 200°C and biological toxicity value LC50 more than 100,000 mg/L.
The new system consists of two basic polymeric components for high temperature rheology and filtration control, along with a special nano-plugging agent, glycol shale inhibitor, extreme pressure lubricant, and barite or formate weight material, providing superior performance for a variety of drilling environments. The system shows the base slurry is light colored and non-toxic to the marine environment, which can be discharged directly into the sea. The environmental friendly feature is a significant superiority over traditional high-temperature systems, such as sulfonated drilling fluid and oil-based drilling fluid which normally require the use of a large number of poisonous additives.
Experiments show that the new system has three important characteristics. Firstly, thermal stability time is more than 72h when aging at 200°C, HTHP filtrate loss is in the range of 12 to 25mL between temperature of 150 and 200°C, and sodium chloride and calcium chloride pollution resistance reach up to 200,000ppm and 5,000ppm, respectively. Secondly, the characteristic of excellent lubricity and inhibition can be comparable to oil based drilling fluids. Thirdly, the low biological toxicity also is one the most important characteristic, 96h LC50 semi lethal concentration of artemia is more than 100,000 mg/L, and EC50 median effective concentration of luminescent bacteria is more than 300,000 mg/L, which meet the biological toxicity discharge requirements for the first level sea area.
The extensive testing results of this new drilling fluid demonstrated its superiority characteristic and low biological toxicity to marine environment. Good results from field testing in Bohai offshore oil field are also presented, the deepest test well depth is 6066m, and the highest downhole temperature is 204°C.
Our industry continues drilling more challenging wells - deeper and higher dogleg severity (DLS). Bottom Hole Assemblies (BHAs) have also become more complex and required to sustain higher loads. The current design and engineering practices still rely on prevention mechanical overload which based on calculated maximum stress versus component material yield strength. While fatigue failure is well known and recognized as the primary cause of component twist-offs downhole, but there still limited approach to prevent it during planning phases such as BHA design, execution monitoring, and evaluation. The industry still relies on inspection and traditional cumulative pumping hours tracking as a preventive action against fatigue failure.
Fatigue damage consists of two stages, crack initiation and crack propagation, with crack initiation accounting for most of the total life. Rotating bending is the driving force for fatigue cracking. It induces cyclic stresses and strains at the stress risers, which are the fatigue-critical features. Fatigue data can be presented in the form of S-N curves, where S is the applied bending stress and N is the total life in a number of cycles. An advancement in BHA modeling with the capability of finer detailed finite element modeling of drilling tool component allows for accurate calculation of BHA bending moment distribution. Given a bending moment, the cyclic stresses and strains at the most critical feature of the most critical BHA component can be determined. The life of the most critical component can then be calculated with the stress-life or strain-life curve of the collar material. This governs the life of the entire BHA.
This paper will present the development of new approach on fatigue management workflow which includes bending moment & stress analysis based BHA design, fatigue life prediction and sensitivity analysis during planning and execution monitoring on consumed fatigue life, including job tracking to component maintenance system. The paper will also discuss the accelerated cumulative fatigue due to shock & vibration.
A fatigue management workflow has been created for planning, execution monitoring, and post-job evaluation phases. During planning, the engineer can calculate the expected fatigue life of the BHA and optimize for the expected duration of the job. The result can be used to select reliable components with sufficient fatigue life for the job. While drilling, this method enables the engineer to continuously monitor the consumed fatigue life of any BHA component and make the decision to replace the tool before a failure occurs downhole. After the job, the consumed life can be recorded in the maintenance system to track the remaining life and decide what preventive maintenance is required.
The new modeling approach enables the drilling engineer to optimize performance and managing BHA integrity risk.
A drill pipe Continuous Circulation Device (CCD) system was used by a geothermal operator in Indonesia, with this paper's scope as follows: Demonstrate CCD system performance used to successfully drill two wells to section Total Depth (TD) with reduced Non Productive Time (NPT) related to stuck pipe events; Highlight the engineering design modifications of the CCD system to cope with the harsh and challenging geothermal drilling environment, through the application of lessons learnt and the use of statistical data. These design enhancements to the CCD, provided a robust method for reducing drilling risks and improved operational performance.
Demonstrate CCD system performance used to successfully drill two wells to section Total Depth (TD) with reduced Non Productive Time (NPT) related to stuck pipe events;
Highlight the engineering design modifications of the CCD system to cope with the harsh and challenging geothermal drilling environment, through the application of lessons learnt and the use of statistical data. These design enhancements to the CCD, provided a robust method for reducing drilling risks and improved operational performance.
The CCD system was used to successfully drill two wells: a total of seven hole sections were drilled from 17 ½" to 7 7/8" in diameter at two geothermal well sites in the same field, onshore Java. The use of the CCD system allowed the rig to maintain constant flow rate of drilling fluid down the drillstring during drill pipe connections. This is paramount to prevent stuck pipe events when total drilling fluid losses are experienced especially in geothermal wells due to their inherent subsurface geological complexity coupled with the risks of formation breakout collapse typical of geothermal well down hole environments. Maintaining dynamic wellbore conditions through circulation and maintaining constant hole cleaning prevents pack offs due to cuttings and formation breakout cavings, settling, and dropout.
The harsh geothermal drilling environment required the CCD system to be modified to operate with higher circulating flow rates and high levels of Lost Circulation Material (LCM) in a total mud losses scenario. The CCD system was developed accordingly through lessons learnt analysis and application, root cause identification, and management of change processes to provide engineered solutions, which were then field tested. The application of this technology improved project economics by reducing NPT related to stuck pipe events and helped in the avoidance of stuck pipe events escalation, resulting in expensive fishing jobs and, potentially, Bottom Hole Assemblies (BHA) lost in hole with consequent sidetracks and associated cost impact.
Abdila, Sayid Faisal (SKK Migas) | Anuraga, Edo (Pertamina EP) | Prayitno, Sugeng (Pertamina EP) | Yoan, M. R. (Mardiana) | Noviasta, Bonar (Schlumberger) | Pratama, Kevin (Schlumberger) | Febriarto, Hendriyan (Schlumberger) | Astasari, Kanya (Schlumberger) | Agustina, Imma (Schlumberger)
Well M is a vertical shale gas exploration well in Indonesia. The presence of overpressured shale formation dictated the requirement to have a 16-in. intermediate casing string between the 20-in. and 13.375-in. casing to cover an approximately 350- to 1000-m measured depth (MD) interval. The mandatory logging operation in all hole sections required a 12.25-in. pilot hole to be predrilled, to enable the logging tool to get a good measurement quality, before it was enlarged to 17.5 in. for setting the 13.375-in. casing. Several hole opening challenges needed to be considered in this operation: 1) The hole opening tool should pass the 16-in. casing inside diameter (ID) restriction (14.936 in.); 2) the tool needed to be applicable for hole opening with an existing pilot hole (bi-center is not a feasible option); 3) the tool should be able to open the shoe track from 12.25 in. to 17.5 in. for 13.375-in. casing run assurance; and 4) the hole opening needs to be as efficient as possible to eliminate multiple runs.
A dual hydraulically expandable underreamer was proposed to answer all those challenges. The configuration consists of two underreamers with different opening capability, which satisfies the high-ratio opening requirement. The lower reamer opened the hole from 12.25 in. to 14.75 in., and the upper reamer further opened the hole from 14.75 in. to 17.5 in. Because running a tandem underreamer is not a common operation, a thorough vibration analysis must be performed to ensure the tool reams in a stable condition, not only to avoid downhole tool failure but also to produce a smooth borehole. Hydraulics optimization is also critical to ensure both underreamer cutter blocks are fully opened during the run.
The tandem underreamer successfully opened the hole from 12.25 in. to 17.5 in. in one run to the section TD from 980 to 1623 m MD (a 643-m interval). At the surface, both underreamer cutter blocks were still in a good condition with 0-0-NO cutter dull and in gauge condition, which showed a good stability. This is also supported by the success of the 13.375-in. casing run to bottom without any issue, indicating a good and smooth borehole. The tandem underreamer method successfully achieved the high-ratio hole opening objective and saved drilling time by eliminating the unnecessary trip for having two separate underreaming runs.
The underreamer tool mechanism and the criteria by which the dual underreamer configuration became the solution to the main challenges in this case study were documented. The study showed that the prejob engineering work (vibration modeling using dynamic finite element analysis and hydraulics modeling) was a critical part in the success of the operation.
The industry is undergoing a transition into efficient technologies and it has digitalization written all over it. Digitalization not only should be about data, a fancy software, touchscreens and the internet, it is important that solutions are able to connect within existing work processes and with people for companies to truly lead to more efficient and safer drilling operations.
Oil and gas industries are now moving towards using Digital Twin's during the life-cycle of well construction. The concept of Digital Twins was first introduced by Dr. Michael Grieves at the University of Michigan in 2002 through Grieves’ Executive Course on Product Lifecycle Management. Digital Twin is a digital copy of the physical systems and act as a connection between physics and digital world. The digital system gets the real-time data from the mechanical systems which include all functionality and operational status of the physical system. An example from another industry; A Formula 1 team uses data from many sensors used in the car, harnessing data and using algorithms to make projections about what's ahead, and apply complex computer models to relay optimal race strategies back to the driver. Ultimately, to drive faster and safer.
By means of the digital twin of the drilling wells during the life cycle of the drilling by combining digital and real-time data together with predictive diagnostic messages there is seen a lot of advantageous in the improvement of accuracy in decision making and results. This again will help the industry to increase safety, improve efficiency and gain the best economic-value-based decision. A Digital Twin driven by real-time data helps to give operations the optimal plan with focus on safety, risk reduction and improved performance.
In this paper, the concept will first be explained in creating and utilizing a Digital Twin of your well for drilling and how it will directly influence how Drilling/well engineers, managers and supervisors plan, prepare and monitor their drilling operations and then implement learnings on future wells; for faster and improved decision making with direct relation to predicting and avoiding/mitigating NPT while also optimizing operations along with it. Case examples will be shared, showing value from use of the Digital Twin from first introduced in 2008 up until now where operators around the globe have implemented it for multiple uses in the drilling lifecycle.
Toempromraj, Wararit (PTTEP) | Sangvaree, Thakerngchai (PTTEP) | Rattanarujikorn, Yudthanan (PTTEP) | Pahonpate, Chartchai (PTTEP) | Karantharath, Radhakrishnan (TGT Oilfield Services) | Aslanyan, Irina (TGT Oilfield Services) | Minakhmetova, Roza (TGT Oilfield Services) | Sungatullin, Lenar (TGT Oilfield Services)
Success towards waterflood optimization requires the accessibility of downhole contribution and injection, challenging on the conventional cased-hole multi-zone completion where contribution and injection are gathering through sliding sleeve. This paper will describe the success in defining flow profile behind tubing by utilizing Temperature and Spectral Noise Logging.
With response in frequency and noise power when fluid flowing through completion accessories, perforation tunnels and porous media, fluid entry points for producer and water departure point can be located by noise logging. Additionally, conventional temperature logging can usually define degree of intake and outflow along with change in fluid phase as a result of change in temperature. In combination of these implications, downhole flow contribution and injection profile can certainly be determined even though fluid moving in and out through production tubing and casing.
Regarding pilot field implemtation in Sirikit field, two multi-zone-completed candidates have been selected, operations were carried-out for producer and injector according to the programs individually designed including logging across perforation intervals and station stops for multi-rate flow, transient and shut-in periods. Longer well stabilization is necessary for injector. In addition to production/injection logging interpretation by incorporating pressure, temperature, density and spinner data, the temperature simulation model is generated to determine downhole flowing/injecting contribution with parameters acquired during logging, for example, pressure and temperature. The other reservoir and fluid properties, e.g. permeability, thickness, hydrocarbon saturation, skin, heat conductivity and capacity have been analog based on available data from neighboring areas. Therefore, the historical data on production and injection including nearby well performance may be crucial to define necessary input to the model. In association with the interpretation of noise logging which is utilized in locating contributing/injecting zones, the interpretation strongly relies on acquired temperature data and outputs of temperature simulation model to match with measured temperature profile. However, limitations have been documented when dealing with multi-phase flow, especially in low flow rate condition – considered 5 BPD as a threshold. Sensitivity run with associated paramenters in the interpretation can significantly reduce the number of uncertainties to match with measured temperature profile.
Temperature and Spectral Noise Logging to provide input to temperature model can definitely help accessing downhole injection profile for the injector by taking benefit of one phase injecting and having contrast between injecting fluid and geothermal temperatures. This application can significantly improve the waterflood performance and optimization particularly in high vertical heterogeneous reservoirs – thief zones can be identified and shut-off consequently. However, defining downhole contribution for low-rate oil wells producing from multi-layered depleted reservoirs especially in undersaturated condition is still a challenge.
The drilling fluid in a vertical well may only be in the pay zone for few hours while in a horizontal well the time can be measured in weeks. This can cause a significant formation damage problem that has the potential for reducing productivity in horizontal wells during drilling operations. A common practice following drilling operations involove filter cake removal operation followed by displacement of wellbore fluids by completion fluid in order to prepare the well for production operations. Presence of drilling fluids in horizontal wells for several weeks is not considered in the design for cleaning fluid recipies targeting drill-in fluid damage. The filter cake buildup time affect its physical characteristics and thus, on the removal process. This study focused on the characterization and the cleanout of the filter cake during the different buildup stages that may occur in the horizontal section. The focus of this study is to highlight the effects of not promptly removing the filter cake.
Filter press instrument was used to simulate filter cake formation on the wellbore wall at 500 psi and 300°F. The filter cake formation process was performed using oil-based drilling fluid at different buildup times (i.e., 3 hours, 3 days and 3 weeks), under 500 psi and 300°F.
The comparison of the different scenarios showed that a thicker filter cake was formed with buildup time (up to 2.5 inch after 21 days). The CT scan results showed that the heterogeneity increased up to 4 layers and the solubility of in the cleanout fluid decreased to 4% by weight.
Horizontal wells are being a common practice in offshore field development in Bohai Bay recently. Maintaining well trajectory in sweep spot while drilling is one of the key factors to optimize horizontal well’s productivity. However, great challenges are often faced in Bohai Bay area including survey uncertainties while drilling and reservoir geology variation. On the one hand, successful placement of a horizontal well requires accurate landing of the well in the right position and orientation in the reservoir. On the other hand, the trajectory is optimized based on structural geobody variation resulted from the uncertainty of parameters governing the static behavior of the field. Therefore, the ability to update geosteering model in timely manner and to proactively adjust well trajectory in real time are required.
This paper presents an innovative method in Bohai Bay by applying the technology of integrated seismic volume and reservoir geosteering model while drilling to achieve very promising productivity. That is to say, the new geosteering method includes seismic inversion of checkshot calibrating, single/multi-wells reservoir model updating, conventional logging while drilling, and mud logging etc. How to develop new horizontal well steering methodology and software integrated seismic volume of time (or depth) domain, logging while drilling, reservoir modeling result to optimize well planning and placement for high productivity?
Results from lower Neogene Minghuazhen formation tests executed in SuiZhong 36-1, Bozhong oilfield of Bohai Bay clearly demonstrate the following capabilities of the technology. Reduction of the steering need for the tools of distance to boundary included Directional and deep well placement tool. A bridge from three-dimensional geology model to two-dimensional geosteering model before drilling; vice versa, 2D geosteering model update 3D geological model after drilling.
Reduction of the steering need for the tools of distance to boundary included Directional and deep well placement tool.
A bridge from three-dimensional geology model to two-dimensional geosteering model before drilling; vice versa, 2D geosteering model update 3D geological model after drilling.
More People grasp the systematical methodology of integrated reservoir geosteering model and trajectory optimizing while drilling which provide a higher degree of confidence in the drilling process.
An operator was drilling complex big-bore gas extended-reach drilling (ERD) wells from an offshore Sakhalin Island platform. Because of the shallow gas anomaly presence beneath the platform, there was a requirement to set an intermediate casing or liner at ~375-m true vertical depth (TVD), which was between the 30-in. driven conductor at 170 to 175-m TVD and the next casing setting depth of 950 to 1065-m TVD. Due to the well complexity and completion requirements, conventional casing design with no underreaming operations was not an option.
Well reach and complexity significantly increased since the project started in 2007, which called for improvements in wellbore geometry. The wellbore geometry underwent few changes, concluding with the latest most favorable required for a 27 to 28-in. directional tophole out of a 30-in. conductor with the maximum bit size pass-through diameter of 25-in., and setting 24-in. liner at ~375-m TVD. Originally, these types of topholes were delivered in two separate trips. On the first trip, the 24-in. borehole was drilled with a mud motor bottomhole assembly (BHA), and on the second trip, underreaming-only operations were performed to obtain final borehole diameter. This operation required additional rig time and caused excessive vibrations during underreaming. A different type of underreamer was implemented successfully to eliminate vibrations, but it did not reduce the number of trips. The ultimate solution was to run the underreamer below a bent mud motor, enabling simultaneous drilling and underreaming of the directional top hole while steering the trajectory in a crowded subsurface environment. The presence of deviated conductors with 6 to 8° inclination at the shoe in all outer slots played a substantial role in overall success of the operation. It is very unlikely that the same results could be achieved if the outer slot conductors were straight.
Installing the underreamer below the mud motor worked successfully in five recent wells, saving a trip in each well. The tophole trajectory was effectively steered away from the offset wells, creating a no-collision-risk situation. A 24-in. liner was run to the planned depth and cemented. This technique was accepted by the operator for the major offshore project and used as the way forward for the remaining five outer slots.
The successful implementation of the simultaneous drilling and underreaming technique demonstrated the benefits and qualitative acceptance of using an underreamer below the mud motor for the directional tophole in this major Sakhalin offshore project. The knowledge and lessons learned from the project can be applied to other worldwide projects with identical or similar casing design requirements.