Managed-Pressure Drilling (MPD) Field Trials Demonstrate Technology Value

An unconventional shale gas drilling project in the Rincon de la Ceniza onshore field is being developed to reach the Vaca Muerta formation, which is overlaid by the shallower and troublesome Quintuco formation. This formation is composed of two over-pressurized layers located in the middle and near the bottom of the formation. The Lower Quintuco formation may also be naturally fractured, containing oil and gas, trapped in an over-pressurized regime, creating an operational drilling hazard. Pore pressure prediction has a high degree of uncertainty, making the proper mud density selection a difficult task. Offset wells drilled conventionally have incurred significant Non Productive Time (NPT) due to well control events, where accurate kill mud weight definition has been challenging due to the presence of natural fractures. The objective for the drilling campaign was to define an optimal and reliable drilling method that would address the challenges of pore pressure uncertainty in a safe and cost-effective way. The first step was to implement Managed Pressure Drilling (MPD) to control over-pressurized zones and determine the more suitable mud density to control the well. The previous vertical wells were drilled conventionally having Quintuco and Vaca Muerta formations isolated from each other with two different casing strings. The drilling strategy was redefined and implemented in three horizontal wells, but in this time both formations were drilled together in one hole section. The intention was to enable drilling with the minimum mud weight possible, allowing higher Rate of Penetration (ROP) consequently. This was possible to achieve by maintaining constant bottom hole pressure conditions at variable Anchor Point depths along the open hole while drilling Quintuco formation. Before drilling the horizontal section in Vaca Muerta formation, a small and controlled constant underbalanced condition was created and fixed at the deepest Anchor Point depth which was as close as possible to the transition zone between both formations. This successful strategy allowed improving drilling performance, by reducing drilling time from 123.4 to 51.7 days per well and reducing NPT from 30.5% to 7.5% by managing well control events, eliminating one casing string and improving drilling efficiency to increase the ROP. Consequently, the cost of the well was reduced 5.5 MM USD/well when compared with the last well of the campaign without any Health Safety and Environment (HSE) issues. This paper presents the drilling strategy followed to overcome well control events and associated NPT when drilling an unconventional shale gas play with highly uncertain pore pressure profile. Planning, implementation and results from the project are presented.

Heavy Mud Weight (MW) to control HP gas and Loss Circulation zones at the same time is not something operators look forward to. COP's Red Rock field in South Wapiti, Alberta had been a victim of this combination which resulted in high operational costs primarily due to additional casing string, high MW and severe mud losses. On average, AFE's came at a minimum of 20% higher as anticipated bringing the drilling program of the area to being uneconomic. A review of MPD technology with the team created a spark to look at improving performance in the area. A number of objectives were identified for this project which were later categorized as Primary Objectives. Drill to TD with reduced mud weights (MW) in a safe manner Set the intermediate casing on top of HP gas zones utilizing wellbore strengthening Drill ahead into HP zones without any massive mud losses Bring the cost of the wells down in order to save the drilling program of the area Eliminate the Intermediate Casing for a significant cost reduction in future wells Secondary Objectives. Conduct Real Time Formation Evaluation in some formations to verify their potential Increase ROP Cement the Intermediate Casing using a single stage method Assess and evaluate the benefits of a new technology Rig crew training and changes in HSE concepts for an MPD operation A dedicated Engineering team was formed who worked on data collection, research of the area, drilling practices and well engineering. This team was supported by COP's experienced Operations team. A great deal of up front discussion and work was done in planning this project to ensure success. Several well design scenarios were looked at the very initial phase of project, out of which the best design in terms of well engineering, well control, area's known risks and HSE was chosen. During this process COP's engineering team introduced "Fountain Chart Method" which uniquely identifies operating envelope of an MPD operation using optimum mud weights From the initial design the specifications of the MPD equipment were decided upon. A meticulous work was conducted on Process Flow Diagrams (PFDs) of which Well Control was of pivotal importance. Special training was assigned to the rig crew detailing goals of the project, working of MPD equipment and communication skills in the presence of another vendor on site. The HSE alert level was heightened due to the sensitivity of the project and extra emphasis was given on safety meetings highlighting high pressure lines, communication skills and drilling with wellhead pressure on surface. Promising results were seen in a four well campaign which not only brought the cost of the wells down but also made the wells more economic. The lower cost of the wells were a result of an improved ROP in some sections and the replacement of a full intermediate string coupled with a liner with only a single production casing string from surface to TD. An added benefit is the technology helped in studying the formations at low MW which were previously masked due to heavy MWs. Utilizing Wellbore Strengthening (WBS) was also a key in establishing integrity of weaker zones up hole. This in turn, gave a better window of applying surface choke pressures using MPD auto choke system. The success of these wells has led to further implementation in the Canadian BU. As a result, a screening tool was developed for internal review of candidates/fields that may benefit from MPD, UBD or any other unconventional style of drilling (such as Air, Aerated Mud or Foam etc). A process is underway in assessing the benefits of these technologies in COP's drilling portfolio and ways are being looked at in making an effective process for implementing these sorts of high profile projects in the future

This paper presents a method used in combination with Managed Pressure Drilling (MPD) to determine real time pore pressures while drilling a deepwater exploration well. Not only was the pore pressure accurately determined but additional procedures were implemented to improve efficiency. This deepwater well was the first time MPD used on a semisubmersible rig in Myanmar by both operator and the drilling contractor. MPD was used on all the well sections below the surface casing with the main objectives for MPD listed as follows: Safe and efficient drilling of the well to planned TD. Elimination of contingency casing strings. Enhanced influx detection. Determination of pore and fracture pressure while drilling. The expected pore pressure based on seismic interpretation for the well was provided by the geoscience team. It was presented as minimum and maximum pore pressures. Fracture pressures were provided as sand fracture (minimum) and shale fracture pressures (maximum). A large uncertainty in pore pressures was expected. MPD was combined with real time pore pressure prediction to estimate pore pressures. MPD procedures were reviewed and amended as required to reflect the actual well architecture, actual equipment, and rig capabilities. Most MPD projects are designed to maintain a Constant Bottom Hole Pressure (CBHP) and not to determine pore pressures. Since a significant pore pressure ramp was expected as soon as drilling started below the surface casing a solution had to be found. Methods to make connections and dummy connections were reviewed and discussed to assist the determination of pore pressures using connection and background gas indicators. The devised procedure could be used for all drillstring connections including any dummy connections made throughout the entire well to provide the real time pore pressure team with consistent data. Additional procedures were developed to ensure that bottom hole circulating pressures were maintained using a combination of MPD choke pressures and increasing mud weights while drilling. The paper presents the procedures that were developed and implemented to successfully drill the exploration well to TD. These procedures have now been field tested and proven to be successful not only to accurately determine pore pressures but also to ensure mud weight management. The procedures will be used again on future wells to determine pore pressures and manage BHP to ensure that maximum benefits are derived from MPD operations on deepwater exploration wells.

This paper seeks to demonstrate how the use of real-time downhole drilling data can help facilitate the timely, well-informed decision to pull out of hole (POOH) if the rate of penetration (ROP) reduces beyond expectation. The traditional decision process starts with offset ROP comparison. If the ROP is lower than expected, then typically there are two scenarios: either the drill bit has become dull or the formation is harder to drill than expected. If the first scenario is suspected then a cost-benefit analysis is performed whereby the remaining footage is assessed and the time to drill to section TD with the current ROP is calculated and compared to the cost of a new drill bit, rig time and the cost of round tripping to change the bit. However, when the bit is on surface and seen to still have good cutting structure then the round trip has been a waste of time and money and more patience should have been exercised in keeping the drill bit on bottom. With real-time, downhole drilling data it is possible to assess the drillability of the formation and estimate the dull condition of the bit. Primary parameters that are used for this assessment are downhole weight on bit and downhole torque, and their relationship to one another. In addition, the trend of the downhole mechanical specific energy is evaluated. The first case study under discussion was drilled in 12¼-in. section, offshore UAE field. For the initial 4,500ft the average ROP was 80ft/hr, at which point a dramatic decrease in ROP was observed. A reduction in ROP was expected at this point because of formation change, but the magnitude of the reduction was much greater. Because the ROP was expected to reduce, the drilling continued with some short-lived increases in ROP. After a sustained time period of low ROP the decision to POOH was made, when the drill bit was on surface the dull grade was 1-6-HC-S-X-I-RO-PR. Upon evaluation of downhole drilling data with the aid of hindsight regarding eventual dull grade it was seen that there were clear indications that the bit was no longer effective and the decision to POOH should have been made. The time period that elapsed between the drill bit becoming damaged and POOH was 30 hours. This base case lesson learned was utilized on a subsequent well in the drilling campaign on an analogous application. By using this downhole signature a quicker, more effective POOH decision was made. The POOH decision in this case was made after just 2.5 hours compared to the 30 hours on the previous well. Once on surface, the dull grade of the bit was 2-7-WT-S-X-I-RO-PR.

Towards the later part of the 20thcentury, the oil industry has been looking for more safer and beneficial drilling methods, especially in deep waters. The high well/field costs pushed the need for attractive technologies which would optimize drilling. Also ever since the catastrophic events of April 2010 in the Gulf of Mexico, the oil industry has been constantly scrutinized for the health and safety standards or rather the lack of it. The consequences of the blowout highlighted the need for improved kick detection and well control. In deepwater wells, there exists a narrow window between the fracture pressure and the pore pressure. This narrow margin poses a safety hazard both for the well and the crew operating on it. Drilling in these sort of fields require distinctive methodologies to achieve both objectives of safe and optimized drilling. Thus one such method which would optimize drilling and improve well control is Managed Pressure Drilling (MPD). This has been defined as "an adaptive drilling process to accurately control the annular pressure profile throughout the well". This technique would create a pressure profile in the well to be within tolerance and close to the boundaries or limits controlled by the pore and fracture pressure. For the understanding of kick detection, well control and circulation when MPD is being employed, a hypothetical well data with a narrow pressure window is selected and a kick is simulated to be controlled using MPD. The pump rate & mud density is studied and kick detection, well control and circulation is analyzed and interpreted. Obviously with the usage of the MPD tools and equipments during drilling, there would be a difference from conventional kick detection, which could probably be enhanced well control. MPD would thus, be able to properly manage any influxes from the formations thereby protecting the system and structure above and have a telling effect on the Non Productive Time (NPT). This paper aim to differentiate the conventional and MPD method of kick circulation based on simulations of lost time and lost circulation. By obtaining the desired result, we can justify the usage of MPD in a narrow pressure window field/reservoir for improved kick detection, control and circulation and thus drilling optimization.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167985, “Improving Drilling-Operations Efficiency on an Ultranarrow- Margin HP/HT MPD Well by Use of a Mud Cap,” by Joy Oyovwevotu, SPE, Senergy; Eric Low, SPE, Bowleven; and Steve Nas, SPE, Schlumberger, prepared for the 2014 SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 4–6 March. The paper has not been peer reviewed. This paper describes the planning and execution of use of mud-cap fluid in the drilling of an ultranarrow-margin (0.50-lbm/gal window at the planning stage) high-pressure/ high-temperature (HP/HT) well from a jackup rig. Significant operational efficiency was gained from the use of cap fluids, making it possible to drill a well that otherwise would have been nearly impossible to drill with minimum lost time. Introduction The IM field is located in Block MLHP-7 in the Rio Del Rey basin offshore Cameroon in a water depth of 58 m (Fig. 1). At the target reservoir level, Well IM-5 was predicted to be a marginal HP/HT well with an estimated reservoir temperature of 181°C and a reservoir pressure of 9,971 psi (16.80 lbm/gal) at a depth of 3475-m true vertical depth subsea (TVDSS). The Middle Isongo sand, intersected by Well IM-3, was the primary gas/ condensate target, consisting of deepwater sands with interbedded shales. The Middle Isongo target package consisted of three reservoir sands, the deepest two of which had not been penetrated in any of the earlier offset wells; this was the primary target of Well IM-5. A secondary target for Well IM-5 was the Intra Isongo, occurring between the Upper Isongo and the Middle Isongo main target. The well design allowed the 12¼-in.-hole section to be drilled conventionally with statically overbalanced mud weight (MW), but it was impossible to drill the 8½-in. hole without using statically underbalanced MW with managed pressure drilling (MPD). Consequently, it was decided that the 12¼-in. hole would be drilled with MPD so that the crew could become familiar with the procedures and practices that would be needed when the 8½-in.-hole section was drilled. Given the uncertainty in the pore-pressure and fracture-gradient forecast, drilling the 8½-in.-hole section with statically underbalanced MW using MPD was seen as the most efficient means of well construction.

Deep wells drilled down to 4000 m to 4500 m true vertical depth (TVD) in the offshore Kutch-Saurashtra rift basin encounter more than 1500 m of abrasive Deccan Trap volcanics in a 12.25-in. section with target stiff Mesozoic sandstone formations in an 8.5-in. section. Weathered basalt flows, fractured sandstones, tightly cemented siltstones, pyritic shales, abnormal pressures, and complicated transverse isotropic layers test the limits of well construction and engineering design at high-pressure, high-temperature (HPHT) conditions. This reduces the rate of penetration (ROP) and sidetracks with premature termination of wells. Traditional prognosis methods fail to predict the abnormal pore pressure regimes and stress anisotropy created by the disturbed tectonic history and complex geological setting. The operator faced unpredictable flow events and wellbore instability incidents such as cavings, tight pulls, breakouts, and equivalent circulating density fluctuations during drilling. Apart from the drilling and completions challenges, the wellbore instabilities affected openhole logging and coring operations, leading to inadequate formation evaluation. In this paper we present an integrated approach to using geomechanical analyses for determining the mud-weight window, drilling bottomhole assembly (BHA), and optimizing mud chemicals. An anisotropic Mechanical Earth Model (MEM) was built using both horizontal and vertical elastic properties to estimate an accurate stress profile that can guide mud loss zones and completion quality. Engineered drilling bits based on the estimated rock mechanical and stress analysis were selected to improve effective ROP through the more abrasive and compacted rocks. High risk zones were flagged inside the Deccan Trap for mud loss while look-ahead mud weight design for the Bhuj and Jhuran formations were optimized by considering plane of weakness mode of failure. Dynamic hydraulics simulation was conducted for the tripping speed of the Casing and BHA. The casing run-in speed was optimized across the Deccan Trap by pumping lost-circulation material (LCM) additives to mitigate losses. This helped to set casing until the 12.25-in. section at total depth (TD) with a narrow mud-weight window of 0.2 to 0.3 ppg. A mud weight of 12.7 to 13.0 ppg was used initially in the 8.5-in. section based on the look-ahead model and was proactively increased to 13.7 ppg to minimize nonproductive time (NPT) with very few borehole breakouts or fracture plane slippage. This result was quite different from offset wells that were drilled with only 11.5 to 12.2 ppg mud weight, which resulted in many tight-hole and stuck-pipe incidents. Bits were changed to manage mean stress, which was expected in the range of 15,000 to 17,500 psi, with formation strength ranging 9,500 to 23,000 psi. The 8.5-in. section was drilled successfully with fewer bit trips, and the hole condition was in better shape compared to the offset wells. The formation evaluation and completion quality review led to the successful discovery of four new zones with minimal near-wellbore damage. Despite the extreme conditions, there was improvement in the instantaneous ROP by 15 to 20% while drilling an additional 250 m of abrasive formation without any wellbore instability.

Managed Pressure Drilling (MPD) was successfully used to exploit the lower cretaceous Buda, Georgetown, Edwards, and Glen Rose formations in Houston and Madison Counties, Texas. The objective was to economically stimulate and commingle all of these zones. A comprehensive solution was developed to combat the principal causes of cost over-runs due to: 1) weak zones in the shallow formations above the productive intervals, 2) wellbore stability issues caused by sensitive shale formations, and 3) lost circulation caused by natural fractures in the productive interval. The operator was faced with several shallow low fracture gradient intervals above an extremely thick and sensitive shale sequence (Dexter Shale) above a 1,400′ pay interval comprised of multiple fractured carbonate horizons. Moreover, the lowermost productive interval had a significantly higher pore pressure and the potential for significant gas deliverability while the shallower productive horizons had a lesser pore pressure and were primarily oil productive zones with associated gas. Problems encountered included excessive shale production, wellbore collapse, BHA sticking, and severe lost circulation. The operator drilled multiple wells overbalanced with various water based mud systems (conventional approach), in certain parts of the field. Success with water-based mud required a great deal of finesse and the operator was unable to achieve consistent, predictable results in the most prolific producing areas. Unexpected cost over-runs occurred and several wellbores were lost and required re-drilling. Managed Pressure Drilling (MPD) allowed the operator to use Oil Based Mud (OBM) to control the sensitive shale formations while drilling with a mud weight low enough to prevent lost circulation. MPD dramatically reduced OBM losses into extremely high permeability fractures in the productive strata. The operator employed a Rotating Control Head (RCH) along with a gas-buster, choke manifold, fluid handling system, and flare system. This equipment allowed the operator to flow while drilling in the deeper high pressure/high deliverability zones and maintain an “at-balance” bottom-hole pressure in the shallower/lower pressure zones through judicious application of surface backpressure. The oil-based mud eliminated all issues with the sensitive shale formations. A mud weight (including ECD) of about 8.95 PPGE for most of the hole and a baseline LCM load proved sufficient to control lost circulation in most instances. When drilling through intervals with intense natural fracturing, the operator used slugs containing a higher LCM concentration comprised of a broad range of particle sizes. LCM slug materials included cottonseed hulls along with graphite, cellulosic fiber, and CaCO3 to cure/prevent partial lost circulation. In some extreme cases, the operator employed fresh water gel pills (“Reverse Gunk”) to combat total lost circulation. The operator developed a “Mud-Cap” technique to pull the Bottom Hole Assembly (BHA) when Total Depth (TD) had been achieved which improved well control and reduced OBM losses when running and cementing casing. Through producing consistent and economic results over a large number of wells across a large area, the OBM MPD program made the continuous and successful development of the entire field possible.

An innovative proven new tool, the "Fluid Hammer", provides axial percussive force and effective weight transfer to the bit which increases the rate of penetration (ROP) from 30-50% with no impact to bit life. BBJ Tool's patent pending Fluid Hammer together with Suncor Energy Inc. of Calgary, Alberta, Canada has applied the Fluid Hammer in several wellbores with excellent results. The tool is positioned between the bit and the mud motor with an antiback off connection. The relatively simple mechanical design delivers effective agitation to the bottomhole assembly (BHA) and reduces issues in deviated wellbores, such as hole drag and proper weight transfer to the bit. It has been successful in improving ROP in vertical/deviated and horizontal hole sections. The Fluid Hammer has been successful on >80 bit runs in vertical/deviated/horizontal wellbores with water, oil base and nitrified drilling fluid systems. Direct comparisons of formations with and without the Fluid Hammer have been completed. The study compares geological formations, compressive rock strength, mud weight and BHA parameters such as weight on bit, rpm, hole drag and ROP. Resulting sliding ROP matches rotating ROP in horizontal wellbores with the downhole agitation at the bit. Tool design improvements will be further enhanced with the use of an Axial Dynamic Simulator. The Fluid Hammer increases ROP, has no effect on telemetry tools, causes no restriction to pump rate and can be used with any mud system. This tool can be run in conjunction with conventional adjustable housings or rotary steerable tools. No special percussion bits are required and it has been run with a wide variety of conventional bit types and sizes. An additional feature of the Fluid Hammer has been in extended reach horizontal hole sections in which the BHA has been simplified with the removal of conventional agitation tools.

In North America shale gas projects, operators aim to extend the horizontal sections to boost single well production and reduce drilling and completion costs. However, as the horizontal section length increases, especially when the laterals exceed 3500 meters, numerous complex drilling challenges arise. These include issues with weight transfer during slide drilling, high downhole friction and torque, mud losses caused by high mud weight and friction loss in long horizontal section, short service lives and low efficiency of downhole tools, limited capability to track thin strata due to restricted logging equipment, and difficulties in deploying production casing, including risks such as differential sticking and prolonged running times. To address these challenges, this paper presents an optimized well design strategy for the drilling of unconventional extended-reach unconventional horizontal wells. Firstly, a slim hole design is adopted to cut costs related to casing, cement, and drilling fluids. Secondly, the upper drilling string is switched from 4″ to 4.5″ drill pipes to provide enough torque and hydraulic power, and the Bottom Hole Assembly (BHA) utilizes even-wall stator positive displacement motors (PDM) and motorized rotary steerable systems (RSS) to enhance drilling efficiency in the intermediate and horizontal sections. Third, the oil-based mud (OBM) system is optimized for stability, low friction, and employs clay-free invert emulsion, complemented by managed pressure drilling (MPD) to control ECD. Then, downhole vibration sensors integrated into RSS enable predictive maintenance against tool fatigue. Next, drilling bit optimization based on formation strength analysis increases rate of penetration and extends bit life. Next, dual-telemetry xBolt (MWD) technology, combined with azimuthal gamma ray logging (LWD), which precisely reveals bed crossings and boundaries, optimizes wellbore placement. Finally, a specialized casing running tool and robust casing connection ensure successful deployment of 5.5-inchcasings in long laterals. These optimizations delivered outstanding outcomes. Several records were broken, such as the longest 4,875-meter horizontal slim-hole section drilled in a single bit run, with the average sweet zone drilling ratio of 96%, the longest single-run deployment of 5.5-inch and 4.5-inch hybrid casing at a depth of 8,157-meter, and a rapid 17-day drilling cycle without incidents. In recent years, numerous horizontal wells have extended beyond 4,000m in lateral length, achieving an average horizontal rate of penetration (ROP) exceeding 50m/h and an average drilling duration of within 20 days. Finally, These drilling optimizations deployed in the Duvernay shale project have notably reduced per-meter costs and enhanced drilling speed, setting a new benchmark within the Western Canadian unconventional project. These practices has set the stage for continued drilling of extended reach horizontal wells in the development of similar unconventional reservoirs.

A number of oil fields in the Gulf of Thailand are characterized by severely depleted gas sands and unstable coal and shale. Operators drilling high angle and horizontal wells in those fields often have to contend with problems associated with high equivalent circulating density (ECD) and the narrow operating margin between fracture gradient and borehole stability. Reaching total depth in those fields without losing returns is possible but it requires careful management of the ECD, vigilant hole cleaning practices, and controlled drilling. Unfortunately, success comes at the expense of drill time which is unavoidably reduced by those same conventional practices. Automated Managed Pressure Drilling (MPD) was a solution used by one operator to improve drilling efficiency while still avoiding losses and maintaining wellbore stability. By taking advantage of the MPD system’s ability to manage the BHP when the mud pumps are off the operator was able to reduce the static mud weight below wellbore stability and the ECD below the fracture gradient. With the reduction in mud weight the operator was also able to change the mud rheology in other ways that contributed to improved hole cleaning. Managed Pressure Drilling was initially used in a three well program in 2007 and later in an extended six well program in 2009. For most of the wells the drilling plan was the same: conventionally drill out of the 9–5/8” casing with an 8–1/2” bit down to the top of the depleted zones, lighten the mud density and rheology, bring the MPD system on line and drill through the depleted zone to the next casing point. However, midway through the second program the well plans changed and MPD was used to drill the entire 8–1/2” section. For all nine wells, the MPD system remained the same: a dynamic pressure control system with an integrated real-time hydraulics model, an automated manifold and backpressure pump, and early kick detection equipment. Even though the trajectory changed from well to well, surface and downhole conditions remained relatively constant in terms of borehole and drill string geometry, stratigraphic sequence, mud rheology, drilling practices, MPD system, and rig type. Such relatively constant conditions created favorable circumstances for the comparison of conventional and MPD practices. Results show that MPD enabled the operator to avoid losses and achieve noticeable improvements in drilling efficiency and ECD management. In addition, there were noticeable improvements in MPD performance in terms of transition times and BHP control.

This paper presents a case where Managed Pressure Drilling (MPD) was used to drill a challenging exploration well through a pore pressure ramp and to address a well control event in conjunction with conventional methods when an influx was encountered The MPD system was used to drill using primary and secondary indicators, such as background gas, cuttings shape, and changes in ROP to determine if onset of the pore pressure ramp was imminent. The MPD system provided a means to measure the flow in versus the flow out of the well and chokes to add surface back-pressure (SBP) to adjust the bottomhole pressure. The MPD operators monitored the trends as drilling continued and reacted if any indications of a pore pressure ramp were experienced. The pressure ramp was encountered, and the flow out exceeded the flow in. The driller applied more surface back pressure to control the influx and reduce the influx size. The well could not be controlled within the allowable back pressure limitations as outlined by the MPD Operations Matrix, so the well was shut in on the Subsea Blow-Out Preventer (SSBOP). The well was controlled with conventional well control methods, using the Driller's Method. The mud weight was increased to the extent that it was not enough to hydrostatically kill the well, but sufficient to allow operations to resume within a new MPD Operational Matrix adding back pressure to keep BHP overbalanced to the formation. This application of MPD reduced the impact of the influx event and allowed the rig to safely continue drilling and meet the well objectives without losing the hole section.

Recent advancements in drilling technologies have significantly improved operational efficiency and sustainability in the Permian Basin, one of the world’s most important oil and gas production hubs. Innovations such as the integration of digital systems, optimization of bottom hole assemblies (BHAs), and Managed Pressure Drilling (MPD) have contributed to faster well completions, reduced operational costs, and minimized environmental impact. A record-breaking well was completed using real-time data analysis and high-performance drilling equipment, demonstrating how automation and continuous monitoring optimize drilling parameters, enhance rate of penetration (ROP), and reduce non-productive time (NPT). The integration of predictive analytics and machine learning has further enabled dynamic adjustments, improving overall efficiency. The application of MPD in deep wells, particularly in the Wolfcamp D formation, has shown promising results, increasing ROP by 23.8% while lowering drilling fluid costs. Additionally, new approaches in directional drilling have reduced the need for multiple BHAs, streamlining operations and cutting expenses. Beyond drilling performance, water management remains a critical challenge in unconventional oil production. Studies have highlighted the need for sustainable water use, including the reuse of produced water to reduce freshwater consumption and environmental risks. Monitoring groundwater quality is essential to mitigate contamination risks from hydraulic fracturing. As demand for efficiency and sustainability grows, these innovations mark a significant step in unconventional well drilling. With continuous technological advancements, the Permian Basin is set to remain a leader in the oil and gas industry, establishing new benchmarks for future exploration and production.

The drilling process in a 12.25-in. directional section with motor bottomhole assembly (BHA) in one North Kuwait field was impacted by elevated levels of vibrations, which limited weight transfer to the bit and rate of penetration (ROP), thereby affecting overall drilling efficiency. This paper analyzes the effect of introducing an axially operating friction reduction system (FRS) in the BHA while maintaining the dynamic drilling metrics, and the resulting efficiency. The approach comprises quantitative comparison of average ROP required to drill the 12.25-in. section, between well (A) with an FRS in the drillstring and those offset wells (B and C) without the FRS. The wells selected for comparison had identical well trajectory, BHA, and drilling metrics. The FRS consists of two major components – One that generates pressure pulses, and the other that converts these pressure pulses into axial excitations. The excitation keeps the drillstring in a state of constant axial oscillation, which reduces the static friction from interaction with the wellbore, especially in the directional section. Placement analysis to determine the position of the FRS in the drillstring for optimal friction reduction was executed, taking into account the well trajectory, outer diameter (OD) and inner diameter (ID) of BHA components, torque and drag (T&D), weight on bit (WOB), flow rate, and mud weight (MW). The result of the data analysis indicated that, for the same drilling metrics, the addition of an FRS in the drillstring of well A had enhanced the drilling efficiency compared to the offset wells B and C. This was evidenced by the increase in the sliding ROP by 56%, rotating ROP by 38%, overall section ROP by 34%, and reduction in on-bottom drilling hours by 35%. No interference of frequency with the measurement-while-drilling (MWD) tool was observed, and logging-while-drilling (LWD) real-time data was successfully decoded throughout the run. The FRS did not show any compatibility issues with the remainder of the BHA components. The consistent oscillatory excitation of the FRS notably reduced static and dynamic friction. As a result, it successfully assisted in mitigating vibrations and stick-slip (SS), enabling efficient transfer of WOB in the directional section that resulted in performance improvements. The overall study shows that the first FRS run on this field was significant in reducing friction and its resulting vibration in the directional section, the benefits of which include enhanced drilling performance, lower mechanical specific energy (MSE), reduced nonproductive time (NPT) and better tool reliability and maintenance. The result of this initial run has become a benchmark to expand the utilization of the FRS more widely in this field.

Summary The rate of penetration (ROP) obtained with a roller-cone bit is limited by either the cuttings-generation or cuttings-removal process. An ROP model that includes the effect of both the initial chip formation and cuttings-removal processes is presented. Laboratory observations show that the reduction in ROP at high borehole pressure is the result of both local cratering effects and global cleaning effects.