The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Al-Riyami, N. (Exebenus, Stavanger, Norway) | Revheim, O. (Exebenus, Stavanger, Norway) | Robinson, T. S. (Exebenus, Stavanger, Norway) | Batruny, P. (PETRONAS Carigali, Kuala Lumpur, Malaysia) | Meor Hakeem, M. H. (PETRONAS Carigali, Kuala Lumpur, Malaysia) | Tze Ping, G. (Faazmiar Technology Sdn Bhd, Kuala Lumpur, Malaysia)
Abstract O&G operators seek to reduce CAPEX by reducing unit development costs. In drilling operations this is achieved by reducing flat time and bit-on-bottom time. For the last five years, we have leveraged data generated by drilling operations and machine learning advancements in drilling operations. This work is focused on field test results using a real-time global Rate of Penetration (ROP) optimization solution, reducing lost time from sub-optimal ROPs. These tests were conducted on offshore drilling operations in West Africa and Malaysia, where live recommendations provided by the optimization software were implemented by the rig crews in order to test real-world efficacy for improving ROP. The test wells included near-vertical and highly deviated sections, as well as various formations, including claystones, sandstones, limestones and siltstones. The optimization system consisted of a model for estimating ROP, and an optimizer algorithm for generating drilling parameter values that maximize expected ROP, subject to constraints. The ROP estimation model was a deep neural network, using only surface parameters as inputs, and designed to maximize generalizability to new wells. The model was used out-of-the-box, with no specific retraining for the field testing. During field-tests, increased average ROP was observed after following recommendations provided by the optimizer. Compared to offset wells, higher average ROP values were recorded. Furthermore, drilling was completed ahead of plan in both cases. In the Malaysian test well, following the software's advice yielded an increase in ROP from 10.4 to 31 m/h over a 136 m drilling interval. In the West Africa well, total depth was reached ∼24 days ahead of plan, and ∼2.4 days ahead of the expected technical limit. Importantly, the optimization system provided value in operations where auto-driller technologies were used. This work showcases field-test results and lessons learnt from using machine learning to optimize ROP in drilling operations. The final plug-and-play model improves cycle efficiency by eliminating model training before each well and allows instantaneous, real-time intervention. This deployable model is suitable to be utilized anytime, anywhere, with retraining being optional. As a result, minimizing the invisible lost time from sub-optimal ROP and reducing costs associated with on-bottom drilling for any well complexity and in any location is now part of the standard real-time operation solutions. This deployment of technology shows how further optimization of drilling time and reduction in well cost is achievable through utilization of real time data and machine learning.
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.
Zhu, Jun (Vertechs Energy Group) | Zhang, Wei (Vertechs Energy Group) | Zeng, Qijun (Vertechs Energy Group) | Liu, Zhenxing (Vertechs Energy Group) | Liu, Jiayi (PetroChina Southwest Oil & Gas Field Company) | Liu, Junchen (PetroChina Southwest Oil & Gas Field Company) | Zhang, Fengxia (PetroChina Southwest Oil & Gas Field Company) | He, Yu (PetroChina Southwest Oil & Gas Field Company) | Xia, Ruochen (PetroChina Southwest Oil & Gas Field Company)
Abstract In the past decade, the operators and service companies are seeking an integration solution which combines engineering and geology. Since our drilling wells are becoming much more challenging than ever before, it requires the office engineer not only understanding well construction knowledge but also need learn more about geology to help them address the unexpected scenarios may happen to the wells. Then a novel solution should be provided to help engineers understanding their wells better and easier in engineering and geology aspects. The digital twin technology is used to generate a suppositional subsurface world which contains downhole schematic and nearby formation characteristics. This world is described in 3D modelling engineers could read all the information they need after dealt with a unique algorithm engine. In this digital twin subsurface world, the engineering information like well trajectory, casing program, BHA (bottom hole assembly) status, are combined with geology data like formation lithology, layer distribution and coring samples. Both drilling or completion engineers and geologist could get an intuitive awareness of current downhole scenarios and discuss in a more efficient way. The system has been deployed in a major operator in China this year and received lot of valuable feedback from end user. First of all, the system brings solid benefits to operator's supervisors and engineers to help them relate the engineering challenges with according geology information, in this way the judgement and decision are made more reliable and efficiently, also the solution or proposal could be provided more targeted and available. Beyond, the geology information from nearby wells in digital twin modelling could also provide an intuitional navigation or guidance to under-constructed wells avoid any possible tough layers via adjusting drilling parameters. This digital twin system breaks the barrier between well construction engineers and geologists, revealing a fictive downhole world which is based on the knowledge and insight of our industry, providing the engineers necessary information to support their judgement and assumption at very first time when they meet downhole problems. For example, drilling engineers would pay extra attention to control the ROP (rate of penetration) while drilling ahead to fault layer at the first time it is displayed in digital twin system, which prevent potential downhole accident and avoid related NPT (non-production time). The integration of engineering and geology is a must-do task for operators and service companies to improve their performance and reduce downhole risks. Also, it provides an interdisciplinary information to end user for their better awareness and understanding of their downhole asset. Not only help to avoid some possible downhole risks but also benefit on preventing damage reservoir by optimizing the well construction parameters.
Ramasamy, J. (Drilling Technology Division, EXPEC Advanced Research Center, Saudi Aramco, Dhahran, Saudi Arabia) | Al-Arfaj, M. K. (Drilling Technology Division, EXPEC Advanced Research Center, Saudi Aramco, Dhahran, Saudi Arabia)
Abstract In oil and gas drilling industry, drilling fluid plays a vital role and is being circulated through out the drilling operation from spudding to completion. Drilling fluid provides hydrostatic stability to wellbore. It is also used to cool down the downhole tools. In addition to the above mentioned functions, drilling fluid is responsible to carry cuttings to surface, provide lubricity and stabilize shale formation. There are variety of chemicals added to drilling fluid to provide properties viscosity, density, emulsion stability, lubricity and fluid loss control. Developing environmentally friendly additives. Development of drilling fluid chemicals that are sustainable and benign to environment to provide the aforementioned properties is a significant step towards achieving sustainability and reducing carbon footprint besides suitability for drilling across aquifers and offshore environments. We have studied the applicability of used cooking oil to obtain fatty acid and their derivatives and evaluated its performance as emulsifiers and lubricants for drilling fluid applications.
Abstract This paper illustrates the methodology and the challenges faced from the planning to execution phases while implementing digital solutions to overcome the drilling operational challenges. In a candidate well, the package with real-time downhole performance measurement (RT-DPM) software, an automated rheometer, and an automatic data graphic visualization interphase, provided visibility into downhole conditions. This was used to predict potential problems and reduce the likelihood of the common issues related to the drilling operation. The RT-DPM software was successfully implemented in a well to reduce the likelihood of stuck pipe incidents and hole cleaning issues. The implementation has enabled real-time monitoring of annular pressure, equivalent circulating density (ECD), equivalent static density, pipe eccentricity, swab, and surge pressure, allowing optimization of the operation time. The lateral section has been drilled successfully with high overbalance without any operational issues. While drilling the production section with several operational challenges, such as losses/gains environment, and high overbalanced formation with a high probability of potential differential stuck, the well was completed successfully, maintaining a good hole cleaning at any point in the annular space of a well. The visibility of the downhole parameters enhanced the rate of penetration (ROP) and optimized the drilling time. A wiper trip was eliminated due to the excellent hole cleaning and the minimal cutting bed generated. Planning started taking into consideration the key point, which was identified as: the close contact points of the pipe to take the extra measurements to avoid such differential sticking in a high overbalanced formation. The overall results were exceptional from the broomstick, showing the parameters were following the ideal trend with no indications of any tight spots. With a steady pick-up weight, slack-off weight, and break-over torque, the hole was identified to be in very good condition. The oil and gas industry is moving to the automation and machine learning methods, and in this paper we will be presenting the methodology and the challenges faced from the planning to execution phases, while implementing automated digital solutions to overcome the drilling operational challenges.
Abstract Tubular GRE lining technology has been globally applied used since 1960's in eliminating downhole tubular corrosion, replacing the elevated CAPEX of CRA OCTG and assuring steady oil, gas and water flow through the downhole string with its flow assurance benefits. Compared to conventional carbon steel whose failures are frequent, the GRE lined carbon steel provides long lasting protection which results in huge savings in life cycle cost. Likewise, compared to CRA material capable of withstanding corrosion issues, the GRE lined CS provides direct capital cost savings. Apart from the economic benefits, operators deploying GRE lined CS have enjoyed superior well integrity over the life cycle of the well. Abu Dhabi National Oil Company (ADNOC ONSHORE) implemented this technology in 2013 for the water disposal wells (5 wells as trial, all of them were successful). We will share the results of the caliper logs that have been run into these wells and the inspection of tubing pulled out of the disposal wells after 4 years in service. Following the assessment, which was satisfactory, the first Water Injection well with GRE lined tubing has been RIH in 2021, and plans for Oil producers with GRE lined tubing in Q2-2023. Till the time of writing this paper, 19 GRE lined strings have been RIH in Aon's water disposal wells, and 2 strings have been run in water injection wells (under study and field test and assessment). This paper shares the evolution of this technology within the Aon from the first installation to the development of a contract and how Aon geared to absorb this technology in their system. Some of the challenges that faced the company were: The modifications that were required to the wells’ designs. How the service provider was aware of Aon's operational well intervention jobs. How this is compatible with the lining system.
Abstract Potassium chloride (KCl) is typically used in the formulation of cement spacers to inhibit the shales from swelling and dispersion. It serves as a shale inhibitor during cementing operations to ensure good wellbore integrity. To obtain optimum inhibition, a high concentration of KCl might be required. A massive amount of potassium chloride will lead to a negative impact on the environment, cement slurry setting time, and wireline logging methods. This work aims to design and synthesize a novel inhibited cement system with an improved shale inhibition performance and wellbore integrity without harming the ecosystem. A spacer and cement formulation utilizing a novel mixture of different high molecular weight polyamines have been prepared successfully and compared against conventional formulations. Our study includes dispersion testing using representative shale samples and spacer compatibility with water-based drilling fluids and cement. The compatibility investigation included rheology testing, thickening time testing, compressive strength measurements, and free water tests. The study shows that KCl concentration should be monitored carefully to avoid cement immature settings. KCl salt also resulted in improper wellbore integrity due to its low performance in shale inhibition compared to amines. Amines did not result in retardation nor acceleration of cement setting. Representative shale dispersion with cement filtrates and spacers show a high dispersion recovery factor of 96.5%, with the novel polyamine additive compared to 82% with potassium chloride. We illustrated detailed experimental and field applications of a novel mixture of different high molecular-weight polyamines. Contrary to conventional KCl, the new formulation resulted in improved shale inhibition and enhanced wellbore integrity. The value of this study was further validated by the successful execution of cementing a casing installed in a water-sensitive shale formation.
Abstract ADNOC onshore's reservoir development strategy has historically been to drill barefoot wells and perform interventions as production deteriorates. Barefoot wells increase flexibility, lower cost, and reduce operational risk, but unbalanced fluids influx, and early water/gas breakthrough may reduce oil recovery. Autonomous Inflow Control Valve (AICV) technology tackles these limitations while eliminating/reducing the associated risks/costs with other inflow control technologies. This paper presents a series of successful pilot workover interventions deployed in the UAE to revive wells and boost recovery. Successful execution of four UAE onshore assets (two gas shut-off, two water shut-off applications) as part of a pilot to assess and approve the AICV technology initiated a new paradigm in restoring oil recovery and production accessibility of inactive and/or low performing wells. Well selection required screening, robust simulation modelling, and assessments of accessibility and downhole integrity. Stringent reviews of required rig operations, lower completion (LC) designs, and various completion components were conducted. The integrated work between various business unit domains helped create new workflow chains and resulted in the implementation of several best practices in planning, design, execution, and evaluation. LC configurations were optimized by T&D modelling, time lapsed simulations, and the use of reservoir data obtained during rig interventions. The design challenges encountered with the limitation on number/type of isolation packers, segmentation, type of shoe, use of a light workover rig, risk mitigations, field execution, well flowback, best practices, and lessons learned are all addressed highlighting how a shut-in well was revived, and other wells observed drastic improvements in production performance. The impact this has on lowering carbon emissions and associated costs by reducing the need for electricity for lifting, handling, treatment, storage, disposal of water and potential venting/flaring gas and risky interventions is demonstrated. Standard practices and boundaries were successfully stretched to truly show the value of the AICV technology; more than double the usual operator standard of isolation packers were deployed in one well after thorough planning, risk evaluations, and effective collaboration. All four wells successfully reached TD without additional complexities or QHSE incidents. Preliminary assessments for the first well, for example, indicated GOR almost halved while enabling oil production at more than double the pre-shut-in rates. Substantial reductions in carbon emissions and costs are expected over the life of the well. The paper introduces the first ever wells installed with AICVs in the UAE and documents newly established best practices for AICV planning and execution. With hundreds of similar applications globally, the opportunity to revive shut-in wells, reduce unwanted fluid production, and improve ultimate recovery, while lowering costs and carbon emissions is evident. The operator plans to further deploy the AICV across its applicable assets to find hidden barrels from existing reservoirs, and to proactively manage their reservoirs in new wells.
Abstract Effective stuckpipe prediction becomes more challenging and requires real-time advanced analysis of all available drilling data. This paper presents an innovative model to predict stuckpipe incidents. A machine-learning model based on intensive feature-engineering integrated with physical models has been developed. It automates real-time drilling data collection, analysis, and detects the patterns for the most dominating drilling parameters values to achieve the success criteria of early warning signs of stuckpipe incidents. It has been applied on two equal sets of wells either stuck or non-stuck incidents. The model triggers alarms reliably and early before the stuckpipe incidents happen and therefore corrective actions could be taken properly in advance.
Abstract As part of a brainstorming exercise that was conducting, on finding ways to lower well operation and intervention duration and have a better allocation of the Drilling function resources. The idea of using the rigless equipment came into play, prompting a trail in business year 2022. The main objective of this newly developed initiative was to look into opportunities where it could be made use of the light rigless intervention which involves the use of light rigless intervention, which involves the use of specialized equipment and techniques to perform the planned well services rather than the use of a conventional rig or/and heavy equipment. Based on that, an exercise conducted in conjunction with the drilling operation teams was carried out, to review and check the drilling workover schedule for potential wells. The scope of work was defined, cases were studied, and the required resources were prepared. The rigless intervention campaign scope has been completed within planned schedule and budget in addition to these types of light interventions enable use fewer equipment footprint, offer improved safety compared to traditional methods by control risks to workers and use of smaller crew members, and leave a remarkable reduction in carbon emission footprint on each well location which in turn makes a positive differences when it compared with conventional rig-based operations.