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Collaborating Authors
Directional drilling
Longest Slim Hole ERD Wells Campaign with Limited Entry Liner Using Water-Based Mud in Onshore Abu Dhabi
Varma, Esha Narendra (ADNOC Onshore) | Ditzler, Theodore Jay (ADNOC Onshore) | Mwansa, Peter Levison (ADNOC Onshore) | Husien, Mohammad (ADNOC Onshore) | Bahrom, Abdul Raman Bin (ADNOC Onshore) | Saragi, Raymond (ADNOC Onshore) | Samahi, Musabbeh Khamis Al (ADNOC Onshore) | Shamsi, Juma Sulaiman Al (ADNOC Onshore) | Alshaigy, Ahmad Othman (ADNOC Onshore) | Gaurav, Anchit (Churchill Drilling Tools) | Abdelhalim, Khaled (Churchill Drilling Tools)
Abstract Extended reach drilling (ERD) can facilitate the development of untapped resources, reduce greenhouse gas emissions, surface congestion, and drilling costs. This ERD project with lower completion was started with an aim to lower well cost indicators including $/ft and $/bbl. Therefore, the challenge was to drill Slimhole ERD (6-1/8โณ lateral) wells with water-based mud (WBM). WBM is more cost-effective, environmentally friendly, and less damaging to the reservoir than OBM (oil-based mud). The use of WBM instead of OBM can save $2MM per well. The major challenges in drilling Slimhole (6-1/8โณ size) ERD well with lateral le include higher torque and failure to deploy lower completion due to high friction factors. The first pilot well was planned with a liner-less design considering the low friction factors required to drill 15,000โฒ of 6-1/8โณ lateral hole and run the lower completion. The second pilot well was targeting a deeper and tighter reservoir zone with higher downhole temperatures. This involved drilling 12-1/4โณ intermediate hole to the landing point with larger 5-1/2โณ drill pipe. It enabled a push-pipe technique for drilling the lateral hole with improved weight transfer through the curved profile. The 6-1/8โณ lateral hole was drilled with 4โณ high-torque drill pipe, tandem high-flow circulating subs, and specially formulated drilling fluid lubricant. A conventional OBM system provides sufficient lubricity to reduce friction factors as low as 0.10. In this application, a low cost WBM system was made feasible by introducing stable high-temperature lubricant and unique hole cleaning practices. Following this successful achievement, the 5-year business plan has been revised to include 63 similar wells with a projected total savings of ~ $250MM. The Slimhole ERD project has demonstrated substantial value with a 35% reduction in CAPEX. The delivery of these two Slimhole ERD wells overturned conventional drilling and completion practices. The implemented project resulted in saving up to 35% of the well cost and saved 20 days per well compared to a conventional ERD well with 8-1/2โณ hole and OBM. These two Slimhole ERD (15,000โฒ lateral) wells were drilled with a challenging Directional Difficulty Index (DDI) of 7.2. The wells were both completed successfully by running the 4-1/2โณ lower completion to reach the total depth.
Cost-Effective Development Mode for Marginal Oil fields โ Best Practice of CNPC
Wu, Bohong (Research Institute of Petroleum Exploration & Development, PetroChina) | Nie, Zhen (Research Institute of Petroleum Exploration & Development, PetroChina) | Li, Yong (Research Institute of Petroleum Exploration & Development, PetroChina) | Deng, Xili (Research Institute of Petroleum Exploration & Development, PetroChina) | Ma, Ruicheng (Research Institute of Petroleum Exploration & Development, PetroChina) | Xu, Jiacheng (Research Institute of Petroleum Exploration & Development, PetroChina)
Abstract Marginal reserves are an important play in future energy development. Based on the statistics of China National Petroleum Corporation (CNPC), the low permeability and unconventional reservoirs occupied 92% of newly found proven reserves in China. To overcome challenges such as poor reservoir conditions, weak natural energy, low displacement efficiency, and insufficient single well production, CNPC has conducted years of research and operation to cost-effectively develop China's marginal reserves. To develop the marginal fields economically, it is required to maximize single well production, recovery and reservoir sweep with minimum CAPEX and OPEX reasonably. The production enhancement is realized by 3 key technologies, namely, sweet spot identification, multi-layered 3D short spacing horizontal well pattern, and volumetric fracturing techniques. The cost reduction is achieved by the full life cycle practice of utilizing "large cluster, factory" well design and field operation, drilling prognosis optimization, integrated intelligent surface system, and unmanned operation. CNPC cost-effective development mode is practical and successful, marginal fields characterized with heterogeneous, multi-layered oil-bearing intervals with poor continuity are being economically developed in China. By comprehensive geological study, fit-for-purpose technologies application, and geoscience-to-engineering integration, the fracture control degree of horizontal wells increased from 60% to more than 90% based on micro-seismic events, stimulated reservoir volume (SRV) increased by 46.8%, average cumulative oil production per well is more than 100 times than original production in the field. Fast and early cash flow is realized by minimum production facilities. The average drilling cycle is shortened by 61%, the surface facility construction time is reduced by 65%, and the average single well investment is reduced by 42%.
- Asia > China (1.00)
- North America > United States > Texas (0.47)
- Government > Regional Government > Asia Government > China Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- (4 more...)
The Development and Application of Ultra-Short Radius Lateral Drilling Technology in Low-Permeable Reservoir of Western South China Sea
Huang, Yi (CNOOC China Limited, Zhanjiang Branch, Zhanjiang 524057, China) | Liu, Hexing (CNOOC China Limited, Zhanjiang Branch, Zhanjiang 524057, China) | Liu, Zhiqin (CNOOC China Limited, Zhanjiang Branch, Zhanjiang 524057, China)
Abstract L2 formation of X Oilfield in western South China Sea is of characteristic of low porosity, low permeability and well controlled reserves, and long well interval, drainage area and controlled reserves can be significantly increased by adopting ultra-short radial radius drilling technology. Flexible drill pipe and drill bit was used in Well WZ-X1 to perform kick-off operation with only 2.4 m footage to increase inclination from 37 ยฐto 87 ยฐ, and hold its inclination by drilling 60-62 m alongside reservoir with trajectory control margin of ยฑ2ยฐ. This paper highlights the trajectory control technology with research of BHA, build-up and hold drill bit, and accurate calculation. During the field operation, drilling parameters were adjusted on the basis of formation variation and outstanding trajectory effect was accomplished and ultra-short radial radius trajectory control technology was achieved. This technology can solve the problem of trajectory control and extend horizontal section of reservoir. It can increase wellbore drainage area and well control reserves, providing technical reference for future operation.
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin > Tahe Field (0.99)
- North America > Canada > Alberta > Branch Field > Altana Et Al Reagan 10-36-1-19 Well (0.98)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Well Drilling > Drill Bits (1.00)
Abstract The success of drilling new horizontal wells depends on connecting the wellโs surface location with the targeted formation while achieving the desired lateral length. However, the choice of the surface locations can be limited due to difficulties obtaining the permits to drill on these locations. This creates more deviated wellbore designs and decreases the optimized lateral length. To avoid this, a risk matrix will be developed to evaluate the maximum lateral length for different surface locations. The first step to creating the risk matrix is to derive a geometry-focused torque and drag model. This model will utilize the wellboreโs step-out and geometrical torsion, which are resulting of both a deviated well design and a far surface location. In this paper, the step-out for any given well path design will be considered as the sum of the horizontal projections of all the deviated segments of the well trajectory above the last curveโs KOP. The calculation of the step-out will be incorporated into the model, then will be used to calculate the maximum lateral length versus the step-out. A torque and drag model with the simplicity of the soft-string model was created while taking into consideration the wellboreโs geometrical torsion to capture the effect of the wellโs trajectory on the axial forces and the torque. This effect will partially simulate the deformation of the drill pipe using simplified mathematical expressions comparing to the calculations of the stiff-string model. This methodology resulted in the model to be more sensitive to the axial force than the torque. The built risk matrix uses the derived model to highlight one of two mechanisms that determine the dominant constraint that limits the drilling process: either reaching the maximum hook load or the maximum torque, based on the wellbore design. These limits depend on the rigโs capacity and the drilling company. The risk matrix summarizes multiple designs to conveniently compare between different step-out values and their respective maximum later lengths. The risk assessment is quantitative rather than qualitative and is reflected as the percentage used of the dominant constraint for the given designs and the interval of the lateral lengths at which this percentage is reached. The optimum surface location with its step-out is then chosen easily from the created risk matrix. The built model takes a middle position between the soft-string model and the stiff-string model by capturing the geometrical torsion along the wellbore trajectory. This approach enhances the geometrical optimization when calculating the axial force and the torque. The simplified mathematical derivation incorporates the step-out into the model, thus creating the risk matrix to optimize the lateral length based on the surface location.
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Drillstring Design > Torque and drag analysis (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Management > Risk Management and Decision-Making > Risk, uncertainty, and risk assessment (1.00)
Horizontal Well Design and Completion Optimization in the Greater Burgan Field for Heterogeneous Thin Sands, A Case Study
Al-Samhan, Amina (Kuwait Oil Company, Al-Ahmadi, Kuwait) | Jilani, Syed Zeeshan (Schlumberger, Al-Ahmadi, Kuwait) | Al-Nemran, Shahad (Kuwait Oil Company, Al-Ahmadi, Kuwait) | Muhammad, Yaser (Schlumberger, Al-Ahmadi, Kuwait)
Abstract The Greater Burgan field has been on production for over 75 years mainly from the homogenous massive sands of the Burgan clastic sequence. Given the increasing field water cut from these sands, it is now a matter of strategic focus for the asset to target the generally untapped thin, laminated low quality sands to sustain target production. This paper focuses on a case study for a horizontal well design and completion optimization using sector modeling. An updated dynamic model, covering the area of interest, was developed. This is an extremely important tool to achieve the study objectives. A sector model was cut out from the full field dynamic model. Grid refinement was performed on the sector, in both vertical and horizontal dimensions. Newly drilled wells were used to update the model horizons, petrophysical data from offset wells in the sector, including geosteering data from the pilot hole, were upscaled and properties populated across the model. The dynamic model calibration was conducted successfully by including all available well events, workovers, production data, static and flowing bottom hole and well head pressures including all other surveillance data from offset wells. To better match the historical field pressure and water-production, sensitivities were conducted to determine the model response to various parameters including the aquifer strength and faults conductivity. Adjustment of the aquifer strength enhanced the field pressure match, invariably improving the calibration of the model. After model calibration, the horizontal well was implemented in the model, in line with the design scope from the asset. The biggest uncertainty was the oil-water contact (OWC) in the sector near the planned well. Although offset wells gave a reasonable estimate of the OWC, it was used as sensitivity parameter to cover the uncertainty. This was taken forward into the model prediction simulation work. The modeling study provided immense insights into the probable outcomes in terms of actual horizontal well production deliverability. Multiple rate sensitivities were conducted mimicking the different choke sizes which were planned. These were used as a guide for the asset to set reasonable production target rates for the well. The study also provided a technical justification for completion recommendations and optimization with a view to maximizing the well's production over time. The horizontal well has been drilled, completed, and tested in the field. The production test rates were encouragingly consistent with the model predictions. The workflow methodologies adopted in this work have now been extended to other wells being drilled in the field.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (13 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
Abstract This subject Well was drilled as water alternative gas injector in Al Nouf field to optimize and support the pressure sustainability of multiple producer wells across reservoir formation based on MRC / ERD approach. The well have high departure so in order to attain the subsurface targets the production casing needs to be extended. This paper will outline the planning and execution of successfully deployed the longest production casing in ADNOC Onshore well using hydraulically rotating shoe. Planning of this well commenced by meetings and collaboration with subsurface operation and reservoir team with the common objective of drilling a smooth section of over 16,473ft as tangent with max inclination of 83 deg. All the associated risks were highlighted and mitigated by proper planning and engineering analysis such as trajectory, additional wipers trips, collision risks, BHA, hydraulics and casing design. Inhouse research was done to find a quick solution to cater challenge in deploying long production casing down to section TD. A hydraulically operated reamer shoe was then selected to encounter the challenge with some risk mitigation in place. The 9 5/8" casing was successfully landed at the target depth of 16,473 feet and subsequently cemented. All the efforts of hole cleaning, dedicated wiper trip played important role in deploying long intermediate case to section TD. Utilization of rotating shoe played a significant role in clearing the ledges and tight hole due to challenging formation. Rotating shoe was the first deployment in the well where it was identified as a challenging well context and had limited regional experienced. Several previous cases casing being held up in the first run. Despite the fact that a wiper trip has smoothened the hole condition, the parameters that were captured during the running. The detailed analysis and operation feedback from casing running job and subsequent operation will be beneficial to provide other operators in assessing the minimum requirement and suitability of this technology utilization to overcome the drilling challenge. This technical paper will show the importance of this project, with the lessons learned, challenges and its mitigation explained in this paper will support the idea to plan and drill the pilot hole and data acquisition in re-entry wells efficiently with key cost savings also will lead to many more successful dual casings exits for future wells. Successful Deployment Of Longest 9 5/8" Production Casing Across Highly Deviated ERD Well
- Asia > Middle East > Oman > Thamama Group > Shu'aiba Formation (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Nahr Umr Formation (0.99)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-V Formation (0.99)
- (4 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
Abstract: The ability to intervene in extreme extended reach wells using conventional technology has lagged the ability to drill and complete them. This paper intends to describe how the physical properties inherent in carbon composite materials provide a means of deploying logging tools into such a well in combination with a high-performance tractor, and to document a case study where a total depth of 40,600ft was achieved in flowing condition. Extending the distance that a tool-string may be conveyed into a horizontal well by means of tractoring devices is well established. The medium for the conveyance becomes the critical component of the system to both maximize the ultimate depth achievable and to ensure safe retrieval. Low friction, low weight and high strength of the rod all combine to reduce required tractor loading and ensure safe recovery. The rod rigidity confers exceptional depth accuracy and removes the potential of tool-lift at high production rates, allowing logging under conditions that are truly representative of commercial well operation. A well that was drilled to a depth in excess of 40,000ft measured depth, with a trajectory designed to maximise the contact between wellbore and reservoir, was completed with a limited entry liner. A total of 37 compartments with lengths between 700ft and 900ft were separated with swell packer assemblies along a horizontal section of 25,000 ft. Critical information about the production flow, including toe/heel balance, had been unavailable because of the limitations imposed by the available intervention methods. The intervention was designed to fully exploit the physical properties of the carbon composite rod in combination with the most efficient in-well controlled tractoring technology available, and aimed to reach deeper than 40,000ft. Simulations based on previous experience showed that this depth would be achievable with the tractor chosen and further that this could be achieved even with the well flowing at rates of over 50% well capacity. This meant that deferred production could be minimised along with waiting periods for flow stabilisation. The intervention was successfully concluded in a single operation, gathering production data from as deep as 40,600ft. Performance of both rod and tractor aligned with planning simulations with significant margin, indicating further performance enhancements in reach being readily achievable. Successfully reaching the toe section of an extreme extended reach well and consequently proving the accuracy of the prediction models for both rod and tractor performance demonstrates the ability to gather production data from previously unreachable areas of high value wells. For intervention engineers, precise planning becomes possible in even the longest of extended reach assets. Drilling of such extended reach wells from artificial islands reduces well counts, accelerate development and increase oil recovery y unlocking reserves from the tight rock and areas that are currently unreachable from existing islands and wellhead platforms. Technology solutions like carbon composite rod and high-performance tractors enable the operator to acquire production logs and perform well services effectively to maintain the life cycle of extended reach wells inaccessible with conventional solutions.
- Asia > Middle East > UAE (0.29)
- North America > United States > Texas (0.28)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Enzyme-Based Cleanup Fluid for High Temperature Filtercake Removal Applications
Al-Taq, Ali A. (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia) | Al-Ibrahim, Hussain A. (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia) | Alsalem, Ali A. (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia) | Alrustum, Abdullah A. (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia)
Abstract Mud-induced damage is highly pronounced in horizontal wells due to the longer period of exposure to drilling mud and low draw-down pressure. Enzyme-based cleanup fluids are preferred for filtercake removal applications, especially in horizontal wells due to their several advantages compared to conventional cleanup fluids. The advantages include low reactivity, less corrosivity, more environmentally safe, polymer-specific enzyme breakers, and ultimately homogenous filtercake removal coverage. Most enzyme-based cleanup fluids are limited to low temperatures. In this study, extensive lab work was conducted to evaluate an enzyme-based/in-situ generated organic acid cleanup fluid for a water-based mud at a temperature of 250ยฐF. The experimental work included coreflood experiments, HT/HP filter press, and see-through cell. Analytical techniques, including ICP, XRD, EDXRF, IFT, and iodine tests, were used to assess the interaction of the cleanup fluid with filtercake components. The results showed that the enzyme/in-situ organic acid generated cleanup system was effective at degrading filtercake for a water-based mu field sample, which was reflected in the obtained return permeability of nearly 83%. Iodine tests confirmed that the enzyme was able to degrade the starch present in the filtercake. The surface tension of fluid is generated due to the interaction of the enzyme-based breaker with the filtercake at 250ยฐF and for 48 hours was 31.11 dynes/cm at 22ยฐC, which indicates that this system can help to prevent water blockage problems, especially for gas tight formation. This paper will discuss in detail all experimental results and findings.
- North America > United States > Texas (1.00)
- Europe (0.69)
- Asia > Middle East > Saudi Arabia (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (25 more...)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- (4 more...)
Abstract This paper discusses the added value of a new approach to exiting an existing wellbore, where the normal practice forces the plug and abandonment (P&A) of the existing lateral before cutting the window into a new lateral, particularly when an off-bottom cemented (OBC) liner is required. The new approach includes the construction of a Technology Advancement of Multilaterals Level 4 (TAML 4) junction to maintain well integrity and the successful development of a re-entry window that allows access to both the existing and the new slim wells. Not only has this technique unlocked massive potential, but it has also led to an enhancement in the utility and reduction in capital expenditure (CAPEX). The successful Level 4 sidetrack and re-entry window deployment is directly related to the robust system design. The application developed includes an anchor with a guide and high-torque capability, a TAML Level 4 junction created in a shape that will lead to smooth, repeatable access in the future, and a customized re-entry window system to further maximize the well potential. The true value is in allowing access to both the existing and the newly drilled lateral without using a rig or decompleting the well. Such operations use tubing exit whipstock (TEW) and pressure isolation sleeves, both of which can be run and retrieved in a rigless manner. The rigless access has allowed the existing lateral to be used as an observation well. Using permanent downhole gauges (PDHGs) enables real-time monitoring of the pressure and temperature and periodic logging to evaluate the reservoir. The newly drilled lateral can be the primary producing lateral; rigless access equally helps recover the well in case of any production challenges. The newly designed multilateral is a game changer for both mature and new developments because it maximizes reservoir production and helps reduce CAPEX by requiring fewer wells to be drilled. The improved well integrity minimizes well workover operations, which creates cost savings. This paper discusses the following aspects:A successful Level 4 junction construction from a slim re-entry existing/mature well. Repeatable accessibility to the lateral and motherbore. Meeting the motherbore objective as required. Delivering an OBC lateral liner and maintaining the well integrity.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion (1.00)
- Production and Well Operations (1.00)
Abstract The deep carbonate reservoir formation on this field has proven to be an extreme High-temperature (HT) environment for downhole equipment. While drilling the 5000 - 6500 ft 5-7/8" slim long laterals across this formation, very high bottom-hole circulating temperatures is encountered (310-340 degF) which exceeds the operating limitation for the downhole drilling/formation evaluation tools. This resulted in multiple temperature-related failures, unplanned trips and long non-productive-time. It became necessary to provide solution to reduce the BHCT-related failures. Performed offset-wells-analysis to identify the BHT regime across the entire-field, create a heat-map and correlate/compare actual formation-temperatures with the formation-temperature-gradient provided by the operator (1.4-1.8 degF/100-ft). Drilling reports and MWD/LWD/wireline logs were reviewed/analyzed. Reviewed tools-spec-sheets, discovered most of the tools had a maximum-temperature-rating of 300-302 degF and were run outside-technical-limits. Observed temperature-related-failures were predominant in very long slim-laterals, which indicated that some of the heat was generated by high flow rate/RPM and solids in the system. Tried drilling with low-RPM/FR, did not achieve meaningful-temperature-reduction. After detailed risk-assessment and analysis on other contributing factors in the drilling process, opted to incorporate mud-chiller into the surface circulating-system to cool-down the mud going into the well. Upon implementation of the mud chiller system, observed up to 40 degF reduction in surface temperature (i.e. temperature-difference between the mud entering/leaving mud chiller). This was achieved because the unit was set-up to process at least twice the rate that was pumped downhole. Also observed reduction in the bottom-hole circulating temperature to below 300 degF, thus ensuring the drilling environment met the tool specifications. The temperature-related tools failure got eliminated. On some of the previous wells, wireline logging tools have been damaged due to high encountered downhole temperature as circulation was not possible prior-to or during logging operation. The implementation of the mud-chiller system has made it possible for innovative logging thru-bit logging application to be implemented. This allows circulation of cool mud across the entire open hole prior to deployment of tools to perform logging operation. This has made it possible for same logging tool to be used for multiple jobs without fear of tool electronic-components failure die to exposure to extreme temperatures. The long non-productive time due to temperature-related tool failures got eliminated. The numerous stuck pipes events due to hole deterioration resulting from multiple round trips also got eliminated. Overall drilling operations became more efficient. The paper will describe the drilling challenges, the systematic approach implemented to arrive at optimized solution. It will show how good understanding of drilling challenges and tailored-solutions delivers great gains. The authors will show how this system was used to provide a true step-change in performance in this challenging environment.
- South America > Brazil (0.47)
- Europe > United Kingdom (0.46)
- North America > United States > Texas (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)