Salomone, Andrea (ENI) | Burrafato, Sebastiano (ENI) | Ricci Maccarini, Giorgio (ENI) | Poloni, Roberto (ENI) | Gioia, Valeriano (ENI) | Concas, Antonio (ENI) | Tangen, Geir Ivan (Lundin Norway AS) | Huse, Arve (Lundin Norway AS) | Antoniani, Lucio (NOV) | Andersen, Mats (NOV) | Zainoune, Sanna (NOV)
This paper presents the positive results of the first deployment of wired drill pipe (WDP) technology and along-string measurement (ASM) tools in drilling operations in the Adriatic Sea. The WDP system was used within the frame of a multi-objective testing program, in conjunction with an experimental downhole tool.
The system allowed transmission of real-time, high-density, low-latency data from logging-while- drilling (LWD) tools and from ASM subs. These tools provided temperature, annular/internal pressure, rotation, and vibration data. This was the first time WDP and ASM tools were used by an operator in the Adriatic Sea. The system was also used for activation and communication with another experimental downhole tool on this project.
The high-speed telemetry system made it possible to achieve impressive operational and performance benefits. Annular pressure measured along the string provided a better understanding of the drilling mud condition and behavior along the wellbore, thereby allowing the operator to stay in the safe mud-weight window and helping them to avoid unintentional hole fractures or collapse.
During pumping in and out of hole, swab and surge were also monitored closely with downhole, real- time measurements from the ASM tools. The same effects were controlled after drilling each stand, when the interval drilled was reamed to ensure sufficient hole cleaning.
While drilling, the system raised the rate of penetration (ROP) limit by removing constraints on data acquisition while still providing the confidence that the hole was being cleaned while drilling. Drillstring vibration was recorded as well, and potential benefit in preventing premature failure of downhole tools were highlighted.
The test verified that improved drilling performance was enabled using WDP technology. Awareness of downhole conditions and a substantial reduction in risk were also benefits. In addition, the technology unlocked bidrectional communication and control with modern downhole tools.
Salomone, Andrea (Eni) | Burrafato, Sebastiano (Eni) | Ricci Maccarini, Giorgio (Eni) | Poloni, Roberto (Eni) | Molaschi, Claudio (Eni) | Huse, Arve (Lundin Norway) | Tangen, Geir Ivan (Lundin Norway) | Regener, Thorsten (BHGE) | Backhaus, Oliver (BHGE) | Grymalyuk, Sergiy (BHGE)
Uncertainty in predicting formation integrity as well as pressure regimes poses significant risks to drilling operations. Several technologies can predict downhole environments in terms of formation strength, kick detection etc., but no solution currently exists for kick isolation. This paper presents an innovative well control and risk mitigation technology that is deployed while drilling and the result of a field test offshore Italy.
The new system is integrated in the bottom hole assembly (BHA), and in case of a kick can shut-in the annulus and the drillstring on demand to confine the influx at the well bottom below the sealing elements. A bypass port that establishes communication with the drillstring and annulus can be opened above the sealing elements to allow adjusting of the mud weight. Downhole pressure above and below the annular seal and inside the string can be monitored in real time. The system is deployed in combination with Wired Drill Pipe to ensure activation and bi-directional communication that is independent of any fluid flow.
The system was run on top of the directional rotary steerable BHA while drilling an 8½-in. hole section. The field test was conducted after drilling more than 500 m of new formation and 90 hours in hole. Prior to the test, the system was pulled to surface for visual inspection. No irregularities were observed. The system was then run back in open hole, activated according to operating procedures and tested by applying pressure into the annulus. The well was monitored and no leakage was observed concluding a successful test. Finally, the bypass was opened, circulation was re-established, and the system was deactivated and then pulled out of hole.
This paper describes the technology features and summarizes the first field test results of a new risk mitigation technology for well control situations. This document also shows how deploying new solutions can help E&P operators improve well control through a cost-effective solution and reduce operational risk in case of formation fluid influx into a wellbore.
Zhang, ZhongPeng (Shell China Exploration and Production Company Ltd) | Wu, Yan (Shell China Exploration and Production Company Ltd) | Luo, Lei (PetroChina Changqing Oilfield Company) | Wang, Xueqin (PetroChina Changqing Oilfield Company) | Fan, Yonghong (PetroChina Changqing Oilfield Company) | Yi, Gang (PetroChina Changqing Oilfield Company) | Chen, Chong (PetroChina Changqing Oilfield Company) | Zhao, Fashou (PetroChina Changqing Oilfield Company) | Zhang, Xiaoping (Engineering Technology Institute, CCDC) | Liu, Wei (Engineering Technology Institute, CCDC) | Dong, Hongwei (Engineering Technology Institute, CCDC)
In many matured fields around the world, the infill well development faces multiple challenges; reservoir depletion caused by existing wells is unavoidable, the remaining area to be targeted by infill is typically relatively marginal, with thinner formations that still bear significant subsurface uncertainty compared with sweet spot area developed in the initial phase. In addition, some fields are impacted by PSC conditions, with a strict time constraint.
When developing infill wells several key aspects have to be considered: starting from potential severe mud losses, drill pipe stuck during the drilling phase, to formation damage, production interference with neighboring wells, earlier load up for gas wells etc.
Shell China developed an integrated approach by considering all these challenges, and successfully implemented it for the Changbei tight gas infill well project.
During the Design Phase, a series of core lab tests were carried out to evaluate the formation damage and related permeability reduction. The lab test results indicated that the permeability reduction as result of water encroaching into water wet rock formation is significant (+90%), causing a "water locking" effect. Another topic pertaining to the Desing phase in the Changbei field is the optimisation of the dual lateral well trajectory based on the expected depletion state of the reservoir. Also discussed is the horizontal well tubing size optimization, which accounted for the selection matrix based on KH, online date (related to PSC end) and expected reservoir pressure (depleted).
In the Delivery phase, the surfactant additive identified through the lab testing has been used into the drilling mud and completion fluid to appropriately mitigate the water locking effect. The lab test results demonstrated that a permeability improvement of at least 10% could be achieved. Furthermore, the surfactant concentration was optimized to maximise the emulsion effect for water treatment and the foaming effect during the drilling phase. This paper also covers the well flowback efficiency improvement achieved by additional nitrogen lifting and prolonged firing time.
During the Well Reservoir and Facility Management phase (WRFM), a study of infill well production interference with existing wells was carried out and the recovery could be maximized at the cluster level.
Qayed Subaihi, Maad Hasan (ADNOC ONSHORE) | Benanjaya, Adi (ADNOC ONSHORE) | Eronmwon, Jude (ADNOC ONSHORE) | Al Shehhi, Shamma (ADNOC ONSHORE) | Ramarao, Subba (ADNOC ONSHORE) | Bin Kuwair, Husam (ADNOC ONSHORE) | Belkadi, Wafaa (Schlumberger) | Molero, Nestor (Schlumberger) | Enkababian, Philippe (Schlumberger) | Rivas, Jose (Schlumberger)
A major operator in onshore Middle East was planning to conduct a water shutoff intervention in an oil producer with very high water cut and a naturally fractured carbonate reservoir. The well was completed horizontal with 18 inflow control device (ICD) elements and 16 swell packers along the production liner and openhole section. The production tubing had an electrical submersible pump (ESP) and Y-tool to allow access to the horizontal section. Due to the complexity of the completion and limited access to the reservoir, an engineered approach combining a precise placement method with a reliable water conformance chemistry was necessary.
The engineered approach relied on the use of coiled tubing (CT) equipped with real-time downhole measurements, high-pressure rotary jetting tool, backpressure valve, and through-tubing inflatable packer. Downhole readings included CT internal pressure, annulus pressure, annulus temperature, and casing collar locator (CCL). They were used both to achieve optimum use of the rest of the bottomhole assembly during the intervention, and to evaluate treatment effectiveness. The selected water conformance fluid system combined a medium-molecular-weight polyacrylamide crosslinked gel for fissure plugging with a nanoparticulate leak off control additive to keep most of the polyacrylamide gel within the fissure network.
In horizontal wells, critical steps for water shutoff, such as proper wellbore conditioning, accurate placement technique and controlled fluid penetration, cannot be accomplished through conventional methods, especially in completions with flow control components, and innovative methodologies are required for efficient intervention. An evolved approach for water shutoff intervention relying on real-time downhole data was implemented for the first time in this field, reducing water production from 1300 B/D to 400 B/D, while increasing oil production from 180 B/D to 350 B/D. In the first run, high-pressure rotary jetting tool was used to condition the wellbore tubulars across the inflatable packer planned anchoring depth. In the second run, the through-tubing inflatable packer was set at the target depth, and the water shutoff treatment was pumped into the formation across the target ICDs. CT real-time downhole measurements were instrumental for accurate depth correlation, ensure optimum differential pressure across the high-pressure jetting tool, to control inflation and anchoring of the through-tubing inflatable packer, and to monitor the water shutoff treatment.
This engineered approach, which leverages the use of real-time downhole data to accurately control the positioning and actuation of high-pressure jetting tools and through-tubing inflatable packers, enables critical interactions with formation and completion. This level of control is critical in water shutoff operations, for it enables the customization of original designs based on the changing downhole conditions to achieve maximum effectiveness of the sealing fluids.
Al-Enezi, Badriya (Kuwait Oil Company) | Liu, Peiwu (Schlumberger) | Liu, Hai (Schlumberger) | Kanneganti, Kousic Theja (Schlumberger) | Aloun, Samir (Kuwait Oil Company) | Al-Harbi, Sultan (Kuwait Oil Company) | Al-Ibrahim, Abdullah (Kuwait Oil Company)
A recent study showed that Tuba reservoir, a limestone-rich formation, has the highest oil in-place of all upcoming reservoirs in North Kuwait. This tight formation has three main layers - Tuba Upper (TU), Tuba Middle (TM), and Tuba Lower (TL) with several reservoir units alternating with non-pay intervals. The reservoir units contain significant proven oil reserves; however, production performance after conventional acid fracturing treatments has been historically subpar. As part of new development plan, two horizontal wells, one in TU and one in TL were drilled to evaluate the production potential of a new completion strategy and technologies.
This paper presents one such technology, a single-phase retarded acid system used as a pilot project study. In contrast with previous conventional emulsified acid systems, the single-phase retarded acid minimized tubing friction, thus enabling high pumping rates for the entire treatment. Alternating with the acid system, a viscoelastic surfactant-based leakoff control fluid system allowed the acid stages to reach deeper into the formation. To aid, degradable fiber technology was pumped in several stages to achieve near-wellbore diversion and further control leakoff into large natural fractures, thus improving the stimulated reservoir volume. These fibers are designed to completely degrade with time and temperature after the treatment. Delivery of the complex acid fracturing treatment was optimized in real time for each stage based on bottomhole pressure trend and response.
Combining a new single-phase retarded acid system with chemical diversion technology has proved to be effective in maximizing lateral coverage and etched fracture half-length. Post-treatment evaluation of TU horizontal well revealed the initial production was as much as 150% higher than offset vertical wells after conventional treatments with gelled acid and as high as 100% higher than a previous multistage horizontal well treated with emulsified acid. The TL horizontal well was just put into production recently and is showing encouraging results considering the lower reservoir quality compared to TU formation.
The success of this technique and technical combination delivered breakthrough results for this region and has engaged new interest in developing the Tuba reservoir.
Zhang, Feifei (Yangtze University) | Islam, Aminul (Equinor ASA) | Zeng, Hao (Sinopec) | Chen, Zengwei (Sinopec) | Zeng, Yijin (Sinopec) | Wang, Xi (Yangtze University) | Li, Siyang (Yangtze University)
Nearly one third of the drilling time lost is caused by stuck drill pipe. In many cases, stuck pipe is preventable if early signs are detected and timely measures are taken, particularly for stuck pipe events caused by solids (primarily drilled cuttings) in the wellbore. This paper presents a physics-based model and data analytics combined approach to predict stuck pipe caused during drilling.
The new proposed method combines the physics-based first principle models, including transient solid transport model, drill string model (torque and drag model) and the data-driven models. The proposed models will be worked based on the analysis of both field and experimental data. The physics-based models capture the basic rules of fluid mechanics, drill string mechanics, and multiphase flow during the drilling operations.
By analyzing field data from historical wells and experimental data, an EnKF based data-driven model is applied to provide parameters and coefficients needed by the physics-based models. The data-driven model improves the reliability of the results predicted by the first-principle based model and allows it to continuously improve itself.
Based on a transient approach, this development can use real-time drilling operational data as inputs, predict the stuck pipe risks, and provide warnings when a high risk for stuck pipe scenarios are encountered. Comparing to existing stuck pipe prediction approaches, the new proposed approach can distinguish the hole cleaning related stuck pipe risk and other reasons to create stuck pipe. This hybrid method in build technology will use as a supporting tool in decision make. Resulting to bring an opportunity for the drillers to avoid the potential stuck pipe incidents by taking a proper action in time.
Deshpande, Kedar (Weatherford) | Celigueta, Miguel Angel (International Centre for Numerical Methods in Engineering) | LaTorre, Salvador (International Centre for Numerical Methods in Engineering) | Onate, Eugenio (International Centre for Numerical Methods in Engineering) | Naphade, Pravin (Weatherford)
Cuttings transport and hole-cleaning is a challenging issue associated with the efficiency of wellbore hydraulics and drilling operation. Traditional methods used to understand hole cleaning problems are based on field observations and extensive flow loop testing to formulate empirical correlations and mechanistic models. The focus of this study is to create digital twin utilizing advanced simulation techniques that provides better insight for cuttings transport and hole-cleaning. This study explores the use of Eulerian-Lagrangian based numerical techniques to estimate critical flow rate needed for efficient hole cleaning. Digital twin for the cuttings transport is formulated utilizing three dimensional Navier stokes equations employing combination of Eulerian and lagrangian approaches to model the drilling mud flow and cuttings interaction with the drilling mud, wellbore walls and between cuttings themselves. One of the important model to estimate the drag force on cuttings is modified for non-spherical cuttings shape coupled with non-newtonian Herschel Bulkley behavior of the drilling mud in this work. The influence of important parameters, such as fluid rheology, rotation of drill-string, and inclination of wellbore on the hole-cleaning process is investigated. Digital solutions are compared against the published data for Newtonian and non-Newtonian drilling fluids under different wellbore configurations. The advanced computational simulation involving novel drag force correlation and unique combination of numerical methods allowed to create digital twin for cuttings transport process accurately. The numerical strategy utilizing modified drag law showed a very good match with experimental results for straight vertical wellbore, the cuttings transport velocity estimated by digital solutions was within 5% difference of experimental results. Further upon validation, numerical results are successfully computed for drill -string rotation effects which clearly showed physics of cuttings transported efficiently with added energy due to rotation. The phenomenon of cuttings bed sliding in inclined and horizontal wellbores is also correctly simulated with the proposed drag law and numerical methods. The proposed methodology works without any issues with high concentration of cuttings and provides detailed insight into cuttings flow path and effect of various operational parameters on hole cleaning. Advanced computational simulations and modification of drag force law assisted in formulating digital twin that provided excellent insights in understanding effects of operational parameters for efficient hole cleaning.
ElGizawy, Mahmoud (Schlumberger) | Lowdon, Ross (Schlumberger) | Breen, Michael (Schlumberger) | Brovko, Katerina (Schlumberger) | Edmunds, Michael (Schlumberger) | Bulychenkov, Konstantin (Schlumberger) | Mussa, Shadi (Schlumberger)
The drilled wellbore is surveyed while drilling at stationary interval when drilling operation stops to connect a new stand. A next generation measurement while drilling MWD tool is developed to take a definitive survey while drilling either rotating or sliding. This has never been possible before where the entire drilling operation had to stop to take surveys. This paper is presenting results of first runs in the region and the gained benefits in drilling cost and time savings.
The current practice is to hold the drill string stationary to take the survey and allow the direction and inclination sensors to survey the wellbore. The survey time varies from 3 minutes and up to 5 minutes for some MWD tools. Any movement to the drill string will compromise the measurements quality where surveys will fail field acceptance criteria and become invalid. A new technology is developed to allow taking continuous measurements from three magnetometers and three accelerometers to determine accurate inclination and azimuth during drilling the wellbore without a need to stop.
The encouraging results from different runs in the region are presented. Potential time and cost savings are quantified. Surveys are taken every stand approximately every 100 ft. An average 500 minutes (8.6 hours) are needed to take wellbore surveys when drilling 10,000 ft well. For the first time, the new next generation measurement while drilling wellbore surveying tool will save this invisible lost time spent to take the stationary surveys. It improves the average rate of penetration, directional control, allows to complete the well in shorter time and saves on drilling costs. The advantages of continuously taking surveys while drilling is further presented and compared the traditional stationary surveys with respect to the improved well placement.
For the first time in the drilling industry it is possible to take definitive MWD surveys while drill string is rotating and drilling on bottom. The surveying results are very encouraging and show the high potential to maximize the drilling performance while save the drilling time and cost.
Heinisch, Dennis (Baker Hughes, a GE company) | Kueck, Armin (Baker Hughes, a GE company) | Herbig, Christian (Baker Hughes, a GE company) | Zuberi, Mamoon (Baker Hughes, a GE company) | Peters, Volker (Baker Hughes, a GE company) | Reckmann, Hanno (Baker Hughes, a GE company)
Self-excited torsional vibrations of the bottomhole assembly (BHA) at frequencies above 50 Hz, so-called "high-frequency torsional oscillations" (HFTO), can damage drilling tools and can increase non-productive time (NPT). A recently developed HFTO-isolation tool protects the drilling tools above this tool from these harmful vibrations. More than 200 field runs were investigated to evaluate the changes in reliability and benefits.
The concept of the isolation tool works similarly to a two-mass flywheel used in automotive drive trains. The design was simulated, lab-tested and first deployed in a field run in 2018. Since then, the isolation tool was successfully used in various fields and applications in the Middle East. HFTO severity while drilling was measured and recorded below and above the isolation tool to verify functionality and to quantify reduction in torsional loads (torque, tangential acceleration) for the measurement while drilling (MWD), mud pulse telemetry (MPT), and logging while drilling (LWD) tools above the tool. In addition, HFTO-related incidents and other drilling performance indicators with and without the new tool were analyzed.
Analysis of the recorded vibration data from several field runs with an additional high-frequency MWD-tool reveals that the isolation principle works consistently. As predicted by simulation, the measured torsional vibration amplitudes above the tool are significantly lower than without using it, demonstrating the effective protection for MWD-, LWD-, and MPT-tools in the BHA.
The tool has proven consistent performance in more than 16,000 accumulated circulating hours. Tool failures caused by HFTO were eliminated, compared to 22 percent of all failures without the isolation tool. The results of an analysis of individual MWD- and MPT-tools used in runs with and without the isolation tool show a significant increase in distance drilled per tool deployment and re-run decisions. This directly translates to increased asset utilization, fewer trips for failure, and BHA handling operations that results in less non-productive time (NPT) and enables drilling in extremely challenging environments more efficiently.
Centeno, Manuel (Schlumberger) | Krikor, Ara (Schlumberger) | Herrera, Delimar Cristobal (Schlumberger) | Sanderson, Martin (Schlumberger) | Carasco, Anant (Schlumberger) | Dundin, Alexander (Schlumberger) | Salaheldin, Ahmed (Schlumberger) | Jokhi, Ayomarz (Schlumberger) | Ibrahim, Sameh (Schlumberger) | Wehaidah, Talal (Kuwait Oil Company)
The complexity of drilling highly deviated wells in Kuwait drives the need for step changing in the well construction mindset, where severe to complete loss of circulation in Shuaiba formation significantly deteriorate the shale layers in Wara and Burgan formations leading to uncontrolled wellbore stability events. Casing while drilling (CWD) and two-stage cementing with a light density cement slurry were introduced as a technology system to drill the highly deviated complex wells through unstable and highly fractured formations. Fit for purpose engineering processes, advanced software solutions, a tailored bit and a bottom hole assembly dynamically simulated for drilling stability and directional tendency behavior were designed. A special light density cement slurry with high compressive strength was also designed to tackle the lost circulation issues when cementing the casing string. The paper will describe how the technologies can work as one system to solve complicated wellbore problems and address the problematic challenges of drilling unstable shales and fractured formations in the same section of the wellbore. This strategy enabled a significant time saving compared to drilling the section conventionally, removing Non-Productive Time (NPT) resulting from additional trips, cement plugs, stuck pipe, and subsequent sidetracks.