SwissLitho (Switzerland)

Abstract Strict environmental regulations in Kazakhstan limit flaring during well cleanup, creating technical challenges for high-pressure wells under sour gas conditions (SPE-172339-MS). Conventional surface Well testing equipment could not meet these constraints, risking delays in production. This paper addresses these challenges through the deployment of ultra-high pressure zero flaring Surface Well Testing package for High Pressure well testing. It evaluates field application, operational feasibility, and implications for regulatory compliance in ultra-high-pressure environments. In comparison, global standards such as the European Union, ETS and US EPA, Subpart W also impose strict controls on flaring and greenhouse gas emissions. By aligning with these frameworks, Kazakhstan's regulatory stance demonstrates both local compliance and broader applicability to international sustainability practices. Karachaganak Petroleum Operating B.V. (KPO), operator of one of Kazakhstan's largest gas condensate fields, faced this challenge directly. Many of its wells on the low-pressure (LP) reservoir have wellhead pressures lower than the production system, and the presence of sour gas added further technical complexity. To address this, SLB and KPO developed the Zero-Flaring package with a surface pressure-boosting system to reinject multiphase well effluents into the production line. First deployed in 2018, it eliminated flaring during LP/HP cleanups. However, the package could only handle wells, which are connected to production line with flowing pressure up to 130barg. Beyond this injection pressure, there was a need to develop an ultra-high-pressure package (UHP) capable of well cleanup and injection at production line pressure exceeding 130barg. Flaring remained the only technically feasible industrial option for UHP well cleanup due to the unavailability of suitable surface equipment capable of cleaning and reinjecting in the production line at ultra high pressure (> 130barg). This approach conflicted with Kazakhstan's strict environmental regulations, which imposed severe flaring limits and threatened to delay or halt production from new UHP wells. To overcome this, Zero-Flaring Ultra High-Pressure (UHP) separation package - a groundbreaking solution enabling flaring-free cleanup of high-pressure wells was developed. The solution was successfully deployed in 2024 during three UHP cleanup operations at the Karachaganak field. The package performed safely and reliably under ultra-high-pressure and sour gas conditions, eliminating flaring and associated CO₂ emissions. It also enabled earlier production readiness, avoided regulatory noncompliance, and significantly reduced carbon footprint. This deployment marked the industry's first field use of a 220-bar-rated separator for surface well testing. The integration of high-specification pressure components and optimized flow assurance management contributed to the system's success under challenging well conditions. This paper discusses the design, execution, and performance of the technology and highlights its scalability for future HP developments requiring environmentally compliant, zero-flaring operations. This paper presents the first deployment of a 220barg rated surface separator used for zero-flaring UHP well cleanup an innovation that sets a new benchmark for ultra-high-pressure operations. It offers insights into equipment application under extremely sour gas conditions and operational workflows that ensure regulatory compliance. The paper provides scalable, field-proven solutions toward low-emission, sustainable energy production.

Abstract The offshore project in Egypt East Mediterranean delivering complex deepwater wells. Because of geological conditions there is a need to set two casing strings in between 20-in. surface casing and 9 5/8-in. production liner. This cannot be done with conventional drilling of hole sections with bit size diameter. The hole enlargement was required in both sections to accommodate 16-in. intermediate liner and 14-in. production casing. Besides, the reservoir section drilled below 9 5/8-in. production liner also required hole enlargement due to completion design. Complex deepwater well architecture called for advanced bottom hole assembly design and advanced engineering during planning and execution phase. There were three sections that required hole enlargement which could be done in different ways. However, different ways have different risks and execution time. The simplest way is the drilling the bit size diameter hole and make additional trip to perform hole enlargement has the longest execution time as well as undesired risks with not properly stabilized bottom hole assembly (BHA) while performing underreaming only operation. A more complicated way of delivering enlarged hole section is to use one underreamer in BHA placed above measurement and logging while drilling (MLWD) tools. This technique requires very short distance of risky underreaming only operation since the entire section is drilled and underreamed simultaneously, however this technique also requires additional trip to perform rathole elimination. The most complex approach delivering enlarged section and performing rathole elimination in a single trip is utilizing two underreamers in BHA. This technique introduces additional BHA complexity and operational risks; however, it can be successfully implemented with proper job planning and execution in place which was done in current project. Additional project challenges such as directional performance in soft unconsolidated formation of 3D well profile were successfully resolved by introducing point-the-bit rotary steerable system (RSS). The dual underreamers BHA technique in which ball activated underreamer placed above MLWD tools and indexing type (flow activated) underreamer placed between MLWD tools and RSS worked well. 17 ½ × 20-in., 14 ¾ × 17 ½-in. and 8 ½ × 9 7/8-in. hole sections successfully delivered intersecting all well geological targets within required tolerance and saving a trip per section in extremely expensive deepwater operations. This technique was accepted for future deepwater projects in Egypt. The successful implementation of this technique in recent deepwater campaign with the 68 % drilling performance improvement shows the benefits and qualitative acceptance for other Mediterranean offshore projects. The knowledge and lessons learnt from the project can be applied to other worldwide projects with identical or similar casing design requirements.

Abstract Perforating in high-pressure, high-temperature (HPHT) wells require extensive engineering preparation to address hazards associated with extreme downhole conditions. Mature HPHT reservoirs often exhibit significant intra-reservoir differential pressure, in some cases exceeding 400 bar between adjacent production units. These conditions, combined with bottomhole temperatures approaching 200 °C, present high risks of gun lift, differential sticking, and tool failure, particularly in multi-zone completions where perforation order is critical. Historically, coiled tubing has been the default conveyance under live-well conditions, but in multi-zone HPHT settings it typically forces a single-run interval that can expose depleted zones to damage due to high overbalance while adding cost, complexity, and surface footprint. This paper describes the engineering and execution of a wireline perforation programme in a deep HPHT completion with ~490-bar differential pressure across a >200-m gross interval. Conveyance was via a 0.28-in OD polymer-locked wireline cable with MP35N armour—a high-strength, sour-service design. The polymer fills between the armour wires better seals armour interstices to help block gas migration, and the small OD reduces drag and wellbore pressure forces on the cable enabling safe conveyance of 70–80 ft of 2 7/8-in guns per run. The perforation order followed a specific pressure-profile-driven zone-by-zone sequence: pre-job simulations (gun lift, differential sticking, and shock loads) established the initial perforating plan and real-time downhole gauge pressure after each run was used to update and re-order the next sequence. Mechanical shock-loading risk was mitigated by qualifying the shock-absorber sub beyond its nominal rating. High temperature failure risk was controlled by using a flask that protected electronics at ~200 °C as well as limiting internal tool temperature build-up by rotating flask tool use. Dynamic underbalance technique was used on select intervals to improve tunnel cleanup and near-wellbore connectivity. Across two wells, a total of 21 wireline runs (perforation plus post-perforation treatments) were successfully completed with no misruns or equipment failures and a total of ~450 m was perforated. Post-treatment pressure trends indicated improved reservoir communication. The method eliminated the need for coiled tubing, reduced operational footprint and complexity, and preserved productivity in depleted zones.

Abstract The objective of the operator is to enhance drilling performance and efficiency by implementing a new technology to achieve consistent Rate of Penetration (ROP). The goal is to consistently drill one mile within the first 24 hours of drilling. Multiple approaches have been tried in the past but achieving consistency was a challenging task, in this case the operator embedding new approaches by utilizing Artificial Intelligence (AI) to achieve consistency in drilling operation. This new approach brings the AI to the rig-site and is tasked to advise driller achieving consistent ROP within safe operation window. This technology incorporated Edge computing technology and human interaction through Human Machine Interface (HMI) to enable driller-AI interaction. Respective formation, rig and tools limitations for drilling operational safety, parameter constraints are set prior drilling each well. Real-time drilling data is aggregated and ingested by the AI at the Edge considering all the prior information and constraints to recommended drilling parameters while honoring operational safety. The continuous feedback loop audits the optimization, providing consistent output for optimized drilling parameters. Deploying AI Edge advisory is expected to significantly enhance drilling efficiency and safety. The system's AI-driven insights optimize the rate of penetration (ROP) and mitigate risks such as Shock & Vibration (S&V), Stick slip (S&S), and dysfunctional mitigation, leading to smoother operations and reduced downtime. System deployment will improve and accelerate decision-making due to high-quality visualizations and real-time data analysis, which help drillers respond promptly to changing conditions. Integration of system with existing rig hardware ensures minimal disruption to existing rig set-up, establishing smooth transition of working environment for the rig crew. Additionally, training and workshops help teams overcome apprehensions about digital enhancement, fostering a positive attitude and smoother adoption of drilling practices for the future. In conclusion, the deployment of AI at the Edge, deployed at rig-site, results in more efficient, safer, and cost-effective drilling operations. The system's adaptability to real-time conditions and its ability to provide actionable insights ensure consistent performance improvements. This leads to a more competent and confident drilling team, ultimately driving better operational outcomes and higher productivity This technology uses proprietary AI with the Detourney model, deployed and performed at the Edge for seamless adoption. It dynamically reacts to real-time drilling conditions, optimizing processes based on downhole observations. The smart AI Planner autonomously navigates workflows via a real-time feed. It embeds hazard identification such as high torque, stick slip, shock vibration and also provides advisory to mitigate risks when detected, then continues normal drilling once risks are mitigated.

Abstract Rigless well testing with monobore completion has become a popular method for multi-zone reservoir testing on land. This paper introduces a new wireless telemetry system which integrates the acoustic signal technology with the wireline and slickline technologies in order to optimize the build-up duration and maximize the reservoir evaluation and improve the well test process. Rigless testing can utilize slickline, wireline and coiled tubing interventions to perforate, kick-off flow and set gauges with downhole shut-in tool (DHSIT). Traditionally, the downhole gauge data will be acquired in memory mode and retrieved for analysis after the build-up is completed. However, the data interpretation may not allow possible extension of the build-up period. The new solution offers the utilization of acoustic telemetry to read-out the data live from an assembly consisting of DHSIT, gauges and acoustic repeater (deployed via slickline prior to the flowback). This downhole set-up will be able to communicate wirelessly with another repeater deployed via wireline during the build-up period. Then, the data is transmitted through wireline to surface for real-time analysis and interpretation. The solution building and validation process included the system integrity test in the warehouse and later deployed in two runs. The first run allowed a design upgrade to improve the signal between repeaters above and below the DHSIT. Based on this, it is recommended adding the centralizers to have better metal-to-metal contact to increase the acoustic signal-to-noise ratio. The second run was successful where the wireless repeater was deployed via wireline after 10 hours from the shut-in time of the DHSIT's valve. It was positioned at 100 ft above the downhole valve and it started downloading all historical data from the gauge memory and kept recording in real-time during 36 hours of build-up. During this time there was no interruption in the data transmission and the data was delivered to petroleum engineers in town for real-time interpretation and decision making. During the pull-out-of-hole, the distance at which the signal would be lost was evaluated. The tool was stopped every 200 ft to check the signal quality and found that the longest distance at which the signal was received at 1,200 ft distance from the valve. The advantage of integration of the wireless telemetry with conventional slickline and wireline operation optimizes the test duration and provides complete reservoir information. It is also recommended to add a valve control option through wireless telemetry to be able to interrupt an on-going build-up episode without additional slickline run. Other recommendations are to improve the retrieval process by knowing the pressure differential and also to reduced number of fishing operations. For the first time, the wireless telemetry was introduced for rigless well testing. It was achieved by adapting the conventional acoustic telemetry used in the DST rig operations and integrating it with slickline and wireline technologies. This is also a step forward in developing real-time controllable DHSIT.

Measuring physical properties along the wellbore is crucial for estimating and modeling rock properties volumetrically in areas of interest. However, shallow well sections are often unlogged due to economic and technical constraints, creating information gaps that hinder our understanding of geological trends in the first few hundred meters. To address this, various velocity-density relationships have been tested to estimate density logs, especially for unconsolidated intervals below the seabed or where gaps exist. This analysis indicates that velocity-density relationships align more closely with a fifth-degree polynomial function than with the commonly used Gardner equation, which relies on an exponential function.

This work revisits and explores benefits and practical aspects of employing inverse scattering series (ISS) based algorithms to predict internal multiples under a new forward prediction parameterization framework. The intricate nature and rapid vertical and lateral variability of multiple generating reflectors pose a limitation for methods relying on prior information about formations and/or boundaries responsible for creating major internal multiples at the reservoir level.

Abstract The birth of autonomous system in a high stake deepwater operation has consistently set new benchmarks for operational excellence, enhancing consistency, improving operational safety and reduction in CO2 emission. The paper will present the first application globally for O&G of autonomous drilling in deepwater and the journey to reach the optimal drilling parameters in the entire campaign, integrating proprietary tools from Business Partners of the project. The autonomous solution facilitates seamless integration and interface with the Rig Control System (RCS) and downhole tools, achieving peak automation on a Drillship fostering a forward-looking intelligent execution of the Standard Operating Procedures (SOP), ensuring procedural compliance, minimizing operational and personal risks, and adapting dynamically to the ever-evolving drilling conditions. Multidisciplinary collaboration during the Well Engineering planning phase, combined with strategic change management and stakeholder engagement in the execution phase, allows the drilling crew to concentrate on engineering processes, thereby enhancing performance through data-driven insights, training and mentoring. This was the first deployment of the automation system on a 7th generation drillship and has significantly improved the rate of penetration (ROP), reduced the well construction days, by decreasing Invisible Lost Time (ILT) thereby bringing down the overall AFE days. The well-to-well learning curve has also ensured each well is better than the previous. The AI adaptive technologies have removed repetitiveness, ensure task consistency and operational efficiency. Its self-driven downhole dysfunctional mitigation capabilities continue to sustain the integrity of both surface equipment and Bottom Hole Assembly (BHA) thereby reducing overall operating cost. With the system automated validation protocol and the Automated Trajectory Design (ATD) engines, the well planning cycle has been reduced delivering a coherent Digital Drilling Program (DDP) allowing for a digitally orchestrated well construction processes while the AI completes the close loop for a seamless drilling execution. The high-performance Edge computing device aggregates data that is available through a secured cloud environment for on-site support team to aid Real-Time decision-making processes. Solutions have been applied on all the drilling campaign project, allowing operator to run entire drilling section in autonomous mode on Drilling ship already equipped with orchestration solution. Benefit extended also to the second drilling ship in use during the campaign, allowing application of AI in advisory mode. The paper will briefly describe real case application and the end-to-end requirement for running an AI enabled autonomous solutions either in an advisory or close loop mode especially on a floater and enumerate the challenges that might be encountered and how to overcome them in close collaboration with all the stakeholders involved.

Abstract Cloud adoption in the oil and gas industry has accelerated, driven by the need for agility, scalability, and performance. However, with this transformation comes the critical challenge of data residency and sovereignty. This paper explores the nuances of data residency from the Exploration & Production (E&P) domain perspective, highlights differences between traditional on-prem solutions and cloud-based infrastructure models, and deep dives into Infrastructure as a Service (IaaS) architecture. The paper discusses industry considerations, regulatory compliance, infrastructure planning, uptime requirements, and data protection strategies, including cloud audits. Using real-world scenarios and architectural illustrations, this work outlines how IaaS can be configured to meet performance and residency requirements of E&P companies, without compromising security or compliance.

Abstract The objective of the paper is to outline the development of an innovative workflow that addresses the descaling operations in sour environment. The discussion will cover proven practices to remove iron sulfide scales while eliminating fluid losses and achieving production recovery from wells. Hydrogen sulfide (H2S) exposure to the personnel involved in this operation was also eliminated by careful risk management resulting in improvement of well site safety. A custom-fit enclosed flowback system for safe and efficient handling of liquid, gas, and solids, including H2S and naturally occurring high risk solids, was key to this new underbalanced (UB) approach. Real-time downhole telemetry from a CT string was also fundamental to understanding the dynamic bottomhole conditions, which included monitoring the equivalent circulation density, and making informed adjustments on rate of penetration, flow rates, and bottoms-up frequency. To address the triple challenge of heavy iron sulfide scale, H2S, and naturally occurring high risk solids, a custom-fit enclosed flowback system was engineered. This system brought proven concepts from CT drilling and well testing together to achieve the target objectives. The main components included a cyclone-type closed-loop solid handling station and a clean-phase fluid-handling system together with a hydraulically operated choke for pressure control. In addition, because of the continuous exposure to sour environment and to the abrasive fluids resulting from the scale cuttings, a tailored risk mitigation plan was implemented for CT pipe integrity. Building on the experience gained from UB CT drilling projects, concepts such as use of high pH working fluids, and real-time CT pipe inspection was deployed. To date, results have been encouraging, and UB mechanical descaling operations have been safely and efficiently completed, resulting in time savings exceeding 35 hours, as well as fluid savings and a total CO2 emission reduction of 20%. This innovative intervention approach brings production sustainability for strategic assets while extending their producing life as well. Experience gained from these innovative well interventions will benefit the intervention industry by improving well site safety and operational efficiency as well as contributing towards NetZero goals.