Bailey, Jeffrey R. (ExxonMobil Upstream Integrated Solutions) | Lathi, Harshit (ExxonMobil Services and Technology Private Limited) | Prim, Matthew T. (Abu Dhabi National Oil Company) | Carson, Andrew D. (ExxonMobil Upstream Integrated Solutions) | Tenny, Matthew J. (ExxonMobil Upstream Integrated Solutions) | Payette, Gregory S. (ExxonMobil Upstream Integrated Solutions)
Lateral vibration modeling of certain BHA (bottomhole assembly) designs has shown great sensitivity to the proximity of stabilizer blades. This paper will explore the nature of the vibrational dysfunction that we call BHA chatter. A frequency-domain model that has been field-proven shows how this dysfunction occurs, its rotary speed dependence, and mitigation methods and results.
A frequency-domain BHA lateral vibration model will be used to illustrate the role of the nodal point constraint in the determination of the dynamic side forces acting at stabilizer and LWD tool blade borehole contacts. These contact forces may be strong functions of rotary speed and BHA contact spacing, especially if the spacing is close.
The relationship between the dynamic contact forces and vibration index model results will be described in relation to the solution to the lateral vibration model. Examination of the dynamic contact side forces associated with these vibration indices reveals the nature of the dysfunction that the indices represent.
The contact forces that push a stabilizer blade to be constrained within a borehole include both static and dynamic components. The static forces are well understood. However, the dynamic forces are difficult to visualize as they are generated by the BHA in motion, and a well-formulated dynamic model is required to evaluate these forces.
Dynamic dysfunction at a particular location along the BHA is revealed by examining the underlying states of a dynamic model. Charts of the dynamic contact side force quantify the amount of dysfunction. Vibration indices comprising the integrated, length-averaged bending strain energy provide a good summary of the overall BHA response that is particularly useful in BHA design investigations, but it is the dynamics of the individual contact points that drive the dynamic response of the model.
Examples of field BHA designs illustrate both good and bad drilling results, generally in agreement with expectations based on the modeling. The literature is full of references to the whirl mode of lateral vibrations. This is commonly accepted. Chatter is a different mode that occurs primarily in response to the spacing of blade contacts. It is difficult for two blades that are close together to simultaneously serve as nodal points. A lateral vibration wave propagating along the BHA may generate alternating wall contact at the two blades, causing a dynamic chatter dysfunction.
Since the foundation of the oil industry, many wells were drilled with an old design. Such wells had been limiting the reserve recovery potential. In extreme cases, some of these wells had been suspended and remedial work is now required to unlock the wells’ potential. This paper presents a case study for restoring production and increasing the salvage value of suspended wells in areas with proven production potential yet declining production yields.
Challenges for drilling the well were found in three key areas: Sidetrack Points: The main concern in this well was the failed cement job in the 9-5/8 in. casing and the pressurized formation above the targeted reservoir that had the potential to create new fluid paths through cement channels. The pressurized formation required a very heavy mud weight of 152 pcf and managed pressure drilling (MPD) to drill the previous well and incurred losses at the same time. By increasing the depth of the sidetrack point and drilling a short radius 5-7/8 in. wellbore in less than 200 ft., the risk of the pressurized formation communicating to the new lateral was eliminated. This saved the cost of drilling two hole sizes and the cost of milling approximately 1,500 ft. of existing 7 in. liner and running a new one as illustrated in Geomechanical Challenge and Petrophysical Demands: Due to fracturing needs, drilling toward a minimum stress direction was required even though this was not preferable from a drilling standpoint. The stuck pipe tendency becomes greater when compared with drilling toward the maximum stress direction in deep wells. Placing the well in high porosity zones required real-time geosteering using high-end logging while drilling (LWD) services in high dogleg environments. By using LWD technology with high bend rates, the required reservoir contact was achieved by drilling less footage than planned. Modified best practices played a major role in achieving these objectives. Running the Liner through the High DLS (Dogleg Severity) Environment: Drilling the short radius resulted in an averaged DLS of 30 deg/100 ft where it also reached a maximum 53 deg/100 ft across some intervals. Due to a high build rate and the azimuthal change required to reach the target. The use of oil base mud and bridging materials along with constant monitoring of mud rheology allowed the liner to be deployed successfully through high DLS section. The plan for centralizers was also modified to reduce liner stiffness while still obtaining isolation from the water bearing reservoir above the target.
Sidetrack Points: The main concern in this well was the failed cement job in the 9-5/8 in. casing and the pressurized formation above the targeted reservoir that had the potential to create new fluid paths through cement channels. The pressurized formation required a very heavy mud weight of 152 pcf and managed pressure drilling (MPD) to drill the previous well and incurred losses at the same time. By increasing the depth of the sidetrack point and drilling a short radius 5-7/8 in. wellbore in less than 200 ft., the risk of the pressurized formation communicating to the new lateral was eliminated. This saved the cost of drilling two hole sizes and the cost of milling approximately 1,500 ft. of existing 7 in. liner and running a new one as illustrated in
Geomechanical Challenge and Petrophysical Demands: Due to fracturing needs, drilling toward a minimum stress direction was required even though this was not preferable from a drilling standpoint. The stuck pipe tendency becomes greater when compared with drilling toward the maximum stress direction in deep wells. Placing the well in high porosity zones required real-time geosteering using high-end logging while drilling (LWD) services in high dogleg environments. By using LWD technology with high bend rates, the required reservoir contact was achieved by drilling less footage than planned. Modified best practices played a major role in achieving these objectives.
Running the Liner through the High DLS (Dogleg Severity) Environment: Drilling the short radius resulted in an averaged DLS of 30 deg/100 ft where it also reached a maximum 53 deg/100 ft across some intervals. Due to a high build rate and the azimuthal change required to reach the target. The use of oil base mud and bridging materials along with constant monitoring of mud rheology allowed the liner to be deployed successfully through high DLS section. The plan for centralizers was also modified to reduce liner stiffness while still obtaining isolation from the water bearing reservoir above the target.
The success in delivering the well and returning it to production after a challenging workover job opens the door for future activity. Restoring wells by employing the short radius drilling technique provides a cost effective solution compared to conventional workover methods in many cases.
In the past, accessing laterals after a multipacker completion system installation in a multilateral well presented significant risks to drilling operations because certain crucial operations, such as acid stimulation, required a rig on location. Recently, a Middle East operator successfully installed an isolated multilateral completion system. The system was deployed in a well located in an onshore field in the Arabian Gulf region. The isolated multilateral system was customized for multilateral wells that require reentry capability to access the lateral. The system provided a completion window equipped with landing profiles and sealbores that enable deflector settings for lateral access or isolation sleeves for lateral control. Additionally, a unique latch coupling allowed for installation at the optimum azimuth and depth of the system for lateral reentry operations. Historically, in installations that required access to the lateral, a pilot hole had to be drilled and subsequently plugged and abandoned to avoid running a dual-packer completion, followed by running a single packer as an alternative to enable safe stimulation of the lateral. Using the new multilateral isolation system enabled the first combined observation and producer well with a dual-packer completion string. The well represented a technical milestone for the service company in the development of multiple reservoir fields.
Sau, Rajes (ADNOC Offshore) | Kiyoumi, Ahmed (ADNOC Offshore) | Amin, Alaa (ADNOC Offshore) | Correia, Gladwin (ADNOC Offshore) | Barghouthi, Abdel Karim (ADNOC Offshore) | Almheiri, Alqasem (ADNOC Offshore) | Wheatley, Edward Jason (ADNOC Offshore) | Ali, Yasser (ADNOC Offshore) | Seabrook, Brian (ExxonMobil Upstream Integrated Solutions) | Angeles, Renzo (ExxonMobil Upstream Integrated Solutions) | Shuchart, Chris (ExxonMobil Upstream Integrated Solutions)
A giant carbonate field offshore Abu Dhabi is being redeveloped using extended-reach-horizontal-laterals up to 20,000 ft with open hole un-cemented liner, drilled from artificial islands. Long horizontal wells provide significant profitability in unit development cost; however it is critical to ensure effective stimulation of the complete lateral to maximize reservoir recovery. Earlier, SPE171800 introduced an innovative liner design for long open hole horizontal completions, namely Limited-Entry Liner (LEL) that enables high rate aggressive stimulation by bullheading technique. This paper will present the field stimulation results of more than five LEL laterals ranging several-kilometers in open hole completions, demonstrating the impact of LEL stimulations in accelerating production and maximizing reservoir recovery.
Several LEL horizontal wells were completed in low-permeability rock to enable high rate bullhead matrix stimulation. ExxonMobil proprietary software is used to design fit-for-purpose LEL that enables acid injection conformance along the lateral and at the same time creates deep-wormholes by high-velocity acid-jets through 3-mm/4-mm holes in liner base-pipe distributed non-uniformly along the lateral, compartmentalized with oil/water-swellable-packers. The execution of the stimulation campaign was made possible through the use of modularized-equipment packages installed on an ADNOC-vessel, utilizing a unique mechanism that locks the package components to frames installed to the vessel-deck. The stimulation package consists of 6×2000HHP pumps delivering up to 60bpm at 10,000psi. The liquid-additive system, 140bbl vertical mixing tank and more than 190,000gallon raw-acid storage tanks are fully automated to enable acid mixing and pumping on the fly at the desired rates, concentrations and recipes.
In order to demonstrate the effectiveness of acid placement and effective stimulation across the entire lateral, real-time Fiber-Optic surveillance techniques (DTS-DAS) were utilized. The recorded thermal and acoustic profiles provided a qualitative and quantitative measurement of the effectiveness of the mechanical diversion delivered by the LEL design. These data will help in corroborating and fine-tuning the model used in lower completion design of maximum reservoir contact wells in future field development. Along with well performance and real-time surveillance, production/injection logging data demonstrates effective stimulation of the entire lateral.
This paper presents field performance results from successful bullhead stimulation of extended reach horizontal well completed with LEL in low-permeability-reservoir. This paper also presents our first application of fiber-optic-DTS-DAS real-time-surveillance during stimulation and post-stimulation water injection. Advanced surveillance data demonstrated the success and effectiveness of the LEL completion and stimulation in extended-reach long horizontal open hole laterals.
A water flooding pattern using maximum reservoir contact (MRC) wells will be utilized for the future developments of reservoirs in a giant brown field offshore Abu Dhabi. The increase in the reservoir contact together with the application of intelligent completion (IC) for the reservoir management is an effective way to improve the sweep efficiency, enhance oil production and minimize early water breakthrough. Meanwhile, the field is much congested with existing wells drilled from offshore well head towers and several artificial islands (AIs). In addition, many MRC horizontal wells have been and will be drilled in the overlaid reservoirs. Hence, well collision alarms are increasing day by day when planning a new well. To meet with the field development perspectives as well as coping with such a critical field circumstance, unique well architectures with a multilateral IC, namely Multilateral Line Drive (MLLD) system are designed and the techno-economic analysis has been completed for specific cases. This system will enable to reduce the overall drilling and completion cost for the field development with no adverse impact and mitigate the well collision risk by minimizing the number of mother wellbores penetrating through the overlaid reservoirs and provide real time monitoring and control to add values to the reservoir management. This paper presents the drilling and completion strategy for the future reservoir developments, the MLLD system designs and associated technical challenges. In addition, outcomes from the case studies are addressed.
Steam injection is one of the most common EOR methods adapted in heavy oil reservoirs. Steam improves the heavy oil mobility by reducing its viscosity via temperature increase. Steam Flood and Steam Cycle are the primary approaches applied widely in a steam EOR project.
Profit maximization of steam flood projects require good reservoir management practices including regular reviews to optimize steam injection. Steam management adjustments are both simple and complex. The steam management adjustments react against performance expectations, such as early or late production response at the production wells
An integrated work effort by the reservoir management team is imperative in the daily surveillance work. This work requires using geological maps, fence diagrams, permeability maps for identifying possible sand channels and preferential steam path, injection profile logs, injection rates/pressure and production data. Synthesizing all this data determines best locations to redistribute available steam. Expected response is lower steam oil ratios, lower wellhead temperature and lower well water cut rates.
This paper, it summarizes the workflow used for steam optimization process in one of Oman steam flood project. The workflow covers the identification through implementation phase where steam adjustments are required. These phases include review of geological description, petrophysical properties, and production and injection trends. This paper also discusses final KPI measures used to judge successful steam management adjustments.
Sudevan, Vidya (Khalifa University) | Shukla, Amit (Indian Institute of Technology, Mandi) | Sharma, Arjun (Khalifa University) | Bhadran, Vishnu (Khalifa University) | Karki, Hamad (Khalifa University)
Middle Eastern countries have the most complex and extensive oil and gas pipeline network in the world and are expected to have a total length of 24066.9km of pipelines by 2022. Routine inspection and active maintenance of these structures thus have high priority in the oil and gas operations. Pigging, the commonly used internal inspection method is expensive and the need for pre-installation procedures for flawless pig operations makes it time-consuming. The external inspection is currently done manually by a group of operators who either drives or walks over the buried pipeline structures. The visual/sensor data collected using various handheld devices are then analyzed manually to identify/locate the possible anomalies. The accuracy of data collected and their analysis highly depends upon the experience of the operators. Also, the extreme environmental conditions like high temperature and uneven terrain make the manual inspection a tedious task. The challenges in the current manual inspection methods can be tackled by using a robotic platform equipped with various sensors that can detect, navigate and tag the buried oil and gas pipelines.
In UAE, the oil and gas pipelines are mostly buried under a berm, a raised trapezoidal structure made up of sand over the buried pipeline structure. The pipelines are buried under the berm either as (i) single pipeline buried in the middle of the berm or as (ii) two pipelines buried on the two edges of the berm. To conduct any external inspection of buried pipelines using a robotic platform, the accurate location of the buried pipeline has to be known beforehand. The proposed Autonomous Robotic Inspection System (ARIS) should have the capability to precisely locate the buried pipeline structure and navigate along with these structures without any fail/skid. A novel hierarchical controller based on a pipe-locator and ultrasonic sensor data is developed for ARIS for detection and navigation over the buried pipeline structures. The hierarchical controller consists of two modules: (i) pipe-locator based tracking controller, that allows the vehicle to autonomously navigate over the buried pipeline and (ii) a sonar-based anti-topple controller which provides an extra layer of protection for vehicle navigation under extreme conditions. An experimental setup, similar to the real buried pipeline condition was built in a lab environment. The autonomous tracking performance of ARIS was tested under various buried pipeline laying conditions. The results obtained show the ability of ARIS to track and navigate along the buried pipeline even in extreme conditions without any fall/skid.
Abaltusov, Nikolay (Weatherford) | Sukhanov, Aleksandr (Weatherford) | Zaripov, Emil (Weatherford) | Orlov, Dmitriy (Tyumenneftegaz) | Enikeev, Ruslan (Tyumenneftegaz) | Pitsyura, Evgeniy (Tyumenneftegaz)
The purpose of the work performed is to show the possibility of using geosteering not only for achieving geological targets but also for supporting directional drilling operations in multilateral wells. Drilling of multilateral "fishbone" design well in complex terrigenous section of Pokur suite in Russkoye field is reviewed as an example. Three kickoff operations with the use of Rotary Steerable System were carried out in an open hole when drilling a horizontal section of the well under review. The well logs of the previous hole were used for optimal selection of the kickoff point. To control the distance to the reservoir boundaries a 3 layers parameter inversion (based on azimuthal resistivity data) was used in addition to density and porosity sensors. As a result of the operations performed, the optimal conditions for kicking off with the Rotary Steerable System, were identified within the geological structure of Russkoye field. Geosteering in real time was successfully used not only for solving geological issues, but for directional drilling as well: optimal kickoff depths were selected for laterals, the trajectory was followed according to the plan; the problems related to bit deflections when the laterals exit the main productive formation were avoided. The geological targets were delivered as well: the length of the hole in the target formation totaled 98.9%.
With the increasing demand for hydrocarbons, unconventional reservoirs are gaining prominence and account for a large percentage of oil and gas production. However, these unconventional reservoirs inevitably include challenges that must be carefully managed while planning an extraction strategy to yield maximum recovery. This paper demonstrates the advantages of an integrated and automated well placement workflow to improve geosteering in complex unconventional reservoirs with maximum hydrocarbon recovery.
Automated well placement technique is controlled by three primary components: (1) an integrated asset model; (2) availability of uninterrupted, real-time log data; and (3) appropriately selected well planning methods. Initially, a dynamically updatable model of subsurface geology is created that combines surface topography, and an initial well trajectory is planned. As the well progresses, new log data are added to the asset model, and an interpretation is made in real time. Incorporating real-time data helps to dynamically update the model and enable a comparison of planned vs. actual deviation surveys for course corrections. This procedure guides the geosteerer to update well plans, run feasibility analyses, and predict subsurface uncertainties ahead of drilling, thus, increasing the reservoir penetration and overall well productivity.
Automated well placement while drilling is a relatively new concept and requires collaboration across various disciplines. Currently, such techniques are gaining importance among operators of unconventional resources as it enhances accuracy in well positioning and provides better production while reducing costs, drilling risks, and uncertainties. In addition, when targeting very thin, geologically complex reservoir layers, it provides a holistic view of the dynamically changing asset. The use of this approach will enable oil and gas operators to make collaborative, cross-domain decisions and streamline existing unconventional workflows.
Ofori, Bruce Agyapong (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Al-Kamil, Ethar Hisham Khalil (University of Basrah)
Loss of well integrity in many horizontal wells in the United States has resulted in huge capital losses to several operating companies. The occurrence of corrosion in horizontal wells in the US is attributed to several reasons. The deposition of iron (Fe) and manganese (Mn) from manufactured steel pipe and the inability to effectively treat the laterals plays a major role in corrosion mitigation in horizontal wells. Corrosion inhibitors are injected into the wells to help reduce the corrosion rates, however the effectiveness of these injection applications is hampered by the types of well design and fluid dynamics. Loss of Fe/Mn in the lateral sections of the well is a major concern for the oil industry. This research will investigate the amounts of Fe/Mn contributions from the laterals and also investigate the relationship between iron and manganese counts from produced water from oil fields in the US. This research will further investigate the mean time to failure in the laterals and suggest proactive plans for mitigating failures based on findings.
High Fe/Mn concentrations could lead to corrosion in producing wells. High densities of Fe/Mn found in produced water analysis reports has been attributed to the abundance of these two elements used in manufactured steel pipe. These elements are used due to their abundance in manufactured steel pipe and their lack of natural presence in formation fluids. Fe and Mn have a known ratio in steel pipe of approximately 100:1 (depending on steel type). These high concentrations could ultimately compromise the wells integrity.
This research emphasizes the need for considering iron and manganese counts as integral part of the corrosion monitoring. Moreover, considering the long lateral casings, which spans several thousands of feet in the US, injection of corrosion inhibitors will be ineffective in reducing Fe and Mn loss in the lateral sections. Monitoring of Fe and Mn over such long laterals is challenging and costly. It has therefore become crucial for oil companies to thoroughly understand the Fe/Mn contribution from the laterals that could lead to corrosion and develop mitigation strategies to lower corrosion rates in such high-risk wells. This will help to implement remedial measures to better define corrosion rates and quantify the risk of failure. This will also enable oil companies allocate resources for further development and not several remediation efforts.