Objectives/Scope This case history paper describes the well integrity challenges Spirit Energy was faced with for executing the drilling operations on the Scarecrow wildcat well in the Barents Sea. The expected reservoir depth on Scarecrow was the shallowest reservoir ever drilled in the Barents Sea being only 188 m below mudline with a water depth of 454 m MSL. Several mitigating actions were implemented to improve robustness of the well integrity such as: – Seismic While Drilling in the pilot hole down to planned depth of the 13 3/8" shoe to reduce reservoir depth uncertainty – Minimum acceptable LOT value at the 13 3/8" casing shoe for allowing drilling into the reservoir – Unknown reservoir fluid; gas gradient used in design – If actual LOT value lower than minimum accepted; P&A well – Well Control training with the crews onshore at Maersk Training Center – Installation of low flow pump to improve control of actual LOT value – Installation of Autochoke system on the rig – Kick drills on the rig focusing on kick detections and optimizing sequence for closing in the BOP – Well control training using the Autochoke system on the rig as part of qualifying the system for use The focus in this paper is to describe the qualification of a new automated pressure control method (Autochoke system) used on the Scarecrow wildcat well in the Barents Sea for circulating out an influx. Simulations and return of experience indicated that manual conventional well control practices would not provide sufficient pressure control precision to maintain bottomhole pressure within the +/- 4 bar (58 psi) operational window required to circulate out an influx. A new automated pressure control method based on a commercial managed pressure drilling (MPD) control system was developed, tested, and DNV approved to achieve the required pressure control precision for both single- and multi-phase scenarios, and permit safe operations. Methods, Procedures, Process A pressure control method was developed to automate control of well control chokes to maintain a constant standpipe pressure, as required during circulating using Driller's Method. The methodology used is comparable to commercial MPD pressure control systems, in which pressure transducer (PT) measurements are input to a control loop which actuates chokes to attain the pressure demand while minimizing overshoot. Unlike a typical MPD installation, in which PTs are typically located upstream of a choke manifold, this installation utilized PTs installed on the rig standpipe, with chokes installed in the well control manifold. The choke control system was improved to automatically compute and account for pressure wave propagation lag due to the distance between the chokes and the control PTs. Results, Observations, Conclusions The system was tested at a test rig in Norway that permitted the injection of air into the standpipe to simulate a gas kick. In multiple test cases, various quantities of air were injected into the standpipe, circulated into the annulus, and finally circulated out of the wellbore with automated chokes operating to maintain a constant standpipe pressure as the air was circulated out of the wellbore and through the chokes. Testing was repeated with varying quantities of injected air and varying standpipe pressure setpoints to validate the process across a range of operating conditions. The control system demonstrated standpipe pressure control precision of +/- 1 bar (14.5 psi) during all test phases, achieving the required precision. Testing under additional operating conditions was conducted to approximate a real-world well control scenario, in which constant casing pressure is maintained while ramping the pumps, and constant standpipe pressure is maintained while circulating out the kick (i.e. first circulation of driller's method of well control). The maximum observed deviation from the control value was 2 bar (29 psi), again meeting the required control precision. Novel/Additive Information These tests were observed, validated, and approved by DNV. The technology was introduced to the field in July 2018.

Low oil prices are forcing the oil and gas industry to reduce the well construction cost. This calls for new and more efficient technologies and methods. Cost optimization may have negative impact on the risk level as less resources are available. Even with a strong focus on risk and new regulatory requirements, the well control risk level is not decreasing, but rather shows an increase. A new workflow has therefore been introduced in a collaborative cloud-based well planning system that combines the most advanced transient, multiphase engine with an automated procedure based on drillers method. The workflow will improve the quality of the well control planning as it will enable a simple way of automatic recalculation when the project context is changing. The data flow and quality control of data will also be improved and result in more up to date planning results. The automation of the process removes a huge amount of manual work that up to know has been required to keep the well control calculations synchronized with the project plan. New engine features unique to well control modeling like transient temperature and full compositional tracking adds resolution and accuracy to the well control planning results and helps deliver consistency in the results. The new workflow will deliver well control calculations with better resolution and accuracy with much less effort than what is normal today and should therefore help to reduce risk and cost associated with well planning.

The objective of this paper is to reduce the computational effort in reservoir flooding optimization problems by a combination of different optimization parametrization methods and model order reduction techniques. We compare three different parametrization methods that reduce the cardinality of the original infinite set of control-decision variables to a finite set. The three methods include a traditional piece-wise constant (PWC) approximation, a polynomial approximation by Chebyshev orthogonal polynomials and a piece-wise polynomial approximation by cubic Spline interpolation. The Proper Orthogonal Decomposition with Discrete Empirical Interpolation Method (POD-DEIM) accomplishes the reduced order modeling (ROM).. We compare a gradient-free global stochastic search approach and a gradient-based local search approach. We used Particle Swarm Optimization (PSO) as a gradient-free algorithm and Interior-Point Optimization (IPOPT) with L-BFGS method as a gradient-based algorithm. First, we compare the performances of the three parametrization methods solved by each optimizer, using fine scale simulations for an increasing level of parametrization refinement. Then, in the second part of this paper, we combine the parametrization methods with the reduced modeling workflow. For a given level of parametrization refinement, we compare the performance of each parametrization method coupled with POD-DEIM, and solved by each optimizer. In this part, we introduce an online training procedure, where the first optimization iteration is used to construct the snapshot matrix. The results demonstrate how refining the control approximation with more decision variables per well lead to better NPV values, but with a higher computational cost. The best NPV was achieved using the highest refining level with Chebyshev polynomial approximation. Both polynomial and piece-wise polynomial approximations served as better training sets for POD-DEIM leading to a more accurate and fast reduced model. With the strategy proposed, POD-DEIM showed the best optimization accuracy for Chebyshev polynomial with the gradient-free optimizer, thus permitting the use of the model reduction methodology for global-stochastic search methods. However, the gradient-based approach seems to consistently outperform the gradient-free approach in terms of NPV and number of iterations for the cases shown.

Managed Pressure Drilling (MPD) dynamic influx control techniques offer substantial advantages over conventional well control, including reduced influx size, and the ability to control and circulate an allowable influx without requiring conventional methods. With careful planning and execution, MPD dynamic influx control can yield considerable increases in safety and efficiency. Many issues with conventional well control, particularly in deepwater operations, can be mitigated or even eliminated using dynamic influx control. Notably, conventional methods passively rely on the influx to increase wellbore pressure sufficiently to balance reservoir pressure, resulting in needlessly large influx volumes. In contrast, MPD methods quickly detect and actively apply pressure to control an influx in a fraction of the volume. Furthermore, conventional influx removal methods are typically slow, leading to drawn out well control events with high likelihood of further complication, such as stuck pipe and secondary influxes. Conversely, using dynamic influx control, an allowable influx may be controlled and removed from the wellbore in a few hours, not days. In this work, methods that address concerns with current well control practices through application of dynamic influx control are outlined. In addition, transient, multiphase simulation is used to demonstrate comparison between dynamic influx control and conventional well control, clearly quantifying potential benefits of adopting these new methods.

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.

Well Integrity issues associated with barrier degradation due to corrosion could significantly impact on production results in mature fields. Sometimes those issues may lead to the severe well control incidents during production phase affecting on the performance of the facilities nearby. This paper describes the negative trend of well control incidents, which was changed, by using innovative approach of secondary barrier evaluation for wells with compromised primary barrier envelope. The objective is to share with the audience special practice of well integrity management using multiple barrier evaluation technology to prevent loss of pressure containment (LOPC) incidents. In addition, the method allows to extend the production life of wells with sustained annulus pressure (SAP) and continue operating those wells under specific conditions and periodic monitoring instead of immediate killing and securing. This "grace period" could be granted based on the known conditions of the secondary barrier envelope until the rig become available to fix the integrity issue and restore the well barriers. Company started drilling activity in 1960's and since that time more than 4,000 wells have been drilled. All wells have carbon steel casings which serves as secondary barrier envelope in case primary barrier fail. Carbon steel easily gets corroded with time in case of insufficient protection and isolation from corrosive environment. Failure of both well barrier envelopes results in well control incidents. Uncontrolled release of hydrocarbons and other reservoir media to surface or aquifers has a strong negative HSE impact: it could be a reason for human injuries and deaths due to pressure, fire and H2S release, environment pollution, deferred production. Additionally, it is associated with unplanned increase in CAPEX and OPEX, reduction of business targets and KPI's, may cause negative impact on Company image and reputation. Innovative proactive method of secondary well barrier evaluation, successfully used to prevent well control incidents, allows Operators to find the right balance between safety and operation, and extend the production life of the wells with integrity issues without jeopardizing safety and integrity conditions in the fields. Paper illustrates how 9 well control incidents have been prevented and 14 wells with compromised primary barrier envelope were allowed to operate for a limited period of time, until the integrity issues have been fixed.

Drilling operations in high-pressure/high-temperature (HP/HT) environments can be very challenging and costly. In an exploration well being drilled in a unique depositional environment, a rapid increase in pore pressure was anticipated, potentially reaching HP/HT conditions of up to 12,000 psi and over 180°C. The absence of close offset wells resulted in a large uncertainty in the magnitude of the pore pressure. This drove the planned casing design, which was limited by kick tolerance and potentially narrow margins between pore pressure and fracture gradient, resulting in planning for up to six casing strings. To respond to this challenge, standard engineering practices were augmented with additional monitoring and predictive modelling solutions to improve well control and to predict and explain complex well behaviour and mitigate the associated drilling risks. The models were calibrated with measured mud properties and wellbore temperatures and pressures during operations. They were then used to simulate, explain, and predict variations in downhole pressures and surface mud volumes. Various innovative applications were used to guide safe operational decision-making. Where conventional practices would not have allowed, this modelling enabled total depth of the well to be reached while incurring minimal nonproductive time and no well control incidents. By understanding wellbore conditions using advanced well control and temperature simulators, abnormalities normally failing the conventional practices could be detected and explained. This improved well control, safety, rig performance, and effective application of resources.

The challenge to maintain production in marginal field and to keep any related activities to be economically justified will require more optimization and innovation. Artificial lift fields using pump require many mechanical well service intervention: to install and to repair the downhole pump. Mechanical well service uses well service rig or pulling unit rig, mainly to pull and to run the tubing. One of main component of the rig is well control equipment system. The complete package of the well control equipment system is about 30% of the rig service package. The equipment may consist of: complete BOP stack, hydraulic power unit with line, choke manifold, kill line and flare line, poor boy separator. The time needed to rig up, test, and rig down the well control equipment package has significant percentage. For simple job of artificial lift mechanical well service which main job is only pulling and running back the tubing, the percentage may be about 20% - 30%. Continuous and routine job of the mechanical well service will give significant cost impact to the total operation expenses. One of the marginal on shore fields in Tunisia, with low productive oil production well, requires innovation to keep the production in economic limit. Cost reduction of the artificial lift well service operation is one of the main options. Optimization of the well control equipment was studied to reduce the field operation cost. Careful risk assessment had been done. Simple and low cost well control equipment was prepared. Additional procedure was introducedandsome documents related to risk control are prepared. Applying the approach, about 25% - 30% of cost saving is identified without sacrify the safety of the operation. Well control equipment standard is an almost matured and well-regulated standard around the world. The main equipment standards are almost the same across regions, countries and companies. Mostly there are two categories of the standards related to well operation: drilling and well service. However, mostly the main well control equipment is the same for both drilling and well service. Off shore well control standard are more stringent than on shore operation. However, mechanical well service,which deals with existing perforation without any reservoir stimulation and very well-known production behaviors, are not specifically categorized in most of the standards. This type of on shore mechanical well service operation has much less risk than drilling or reservoir well service, so it is highly possible to use less well control equipment package with the proper risk assessment according to the field/well condition. The well control equipment applied in the Tunisia field will hopefully give more standard guidance for low risk marginal oil field.

Abstract Openhole horizontal completions in consolidated formations have been commonplace for a number of years. This type of completion has been very successful due to the relative simplicity of the completion design and ability to segment the horizontal production interval by using openhole hydrostatic-set packers. Using inflow control devices (ICDs) in this completion design allows a uniform inflow across the entire horizontal wellbore, which mitigates early water or gas coning into the wellbore. A newly designed ICD has been developed and field-trialed successfully that eliminates the need for an inner string during installation, allowing circulation through the liner while running in hole as well as hydraulic setting of the openhole packers before pulling out of hole with the workstring. This also provides an improved well control condition. A temporary valve system has been incorporated into the ICD design that provides pressure integrity in the liner until after the upper completion has been installed. Once the upper completion is in place, the valves are triggered hydraulically with applied pressure in the production tubing and opened once the differential pressure is removed, allowing the ICD to be reconfigured into the production mode. Once the valves have been opened, the ICD performs normally for the operational life of the well. This completion technology also provides the added benefit of isolating the upper wellbore from the reservoir until after the upper completion is installed. This potentially prevents unwanted and costly fluid losses into the formation before the well is put on production. This paper will describe the new ICD design technology developed for the application and review initial case history well installations in Saudi Arabia. Introduction A common openhole completion design in consolidated carbonate formations is to use ICDs in combination with openhole isolation packers at strategic locations in the openhole section1. The ICDs provide inflow control to uniformly drain the reservoir, therefore reducing the possibility of premature breakthrough of water or gas, whereas the packers provide zonal isolation to eliminate annular flow. This completion design has been successfully installed in many wells worldwide, with a great many completed in Saudi Arabia (Fig. 1). Typically, hydrostatic-set openhole packers have been used due to their demonstrated ability to conform to eccentricshaped wellbores and their differential pressure capabilities. The setting mechanism for these packers is isolated when running in the hole to prevent premature setting. After the liner is installed, the packers are set by shifting open an isolation sleeve in each packer with a shifting tool in the inner workstring as the inner string is pulled out of the liner. Once open, the packers are hydrostatically set with pressure in the wellbore. Smaller sizes require additional setting force than what can be generated only with well pressure, so applied pressure is used in combination with an opposing cup tool to reach the required setting pressure against an internal atmospheric setting chamber. In the larger-size packers, only the shifting of the sleeve is required to flood the setting chamber and generate the required setting force. Once set, a constant setting force is applied to the packing element via the atmospheric chamber. This allows element compensation for possible borehole movement and prevents the long-term loss of packing element sealing force against the borehole.

This paper presents the success story of an innovative milling operation on a stuck-closed tubing master valve performed with electric line technologies. This field application has resulted in restoration of well accessibility, enabled well control, and saved costs related to rig intervention. The paper also documents lessons learned and recommends proper operational procedures related to future similar rigless operations, specifically with regards to well control and barrier philosophy. A stuck-closed surface valve in a live well is treated with extra caution as it presents a serious and challenging well control issue. Such a situation often calls for immediate intervention to restore well accessibility and reestablish well integrity barriers. The stringent well control requirements of the oilfield operator make the operational design and corresponding job execution even more challenging. In this case, Well-A is a land based vertical oil well on which the master gate valve was stuck and non-functional in the closed position. The pressure bellow the valve was last measured to be 1200 psi, a relatively high shut-in wellhead pressure compared to other offset producers in the same field. The wellhead was equipped with two carbon steel master gate valves, in addition, to the swap valve. The lowermost gate valve is the stuck valve, hence, preventing access to the well. Several attempts to repair and grease the valve body and stems were unsuccessful. Accordingly, the oilfield operator has decided to mill the gate valve, secure the well, and then replace the entire tree. The uncertainty in the well pressure below the master valve posed a significant operational risk. This is due to the impact of well fluid pressure force on the electric line rig-up after the gate valve is milled. Therefore, job planning, design, and execution were guided by a risk based and comprehensive contingency plan that accounted for all probable well control scenarios. The rig-up consisted of coiled tubing flanged risers, annular blowout preventer, Shear/Seal ram, and wireline blowout preventer in order to ensure the presence of adequate well control barriers throughout the operation. Adhering to a ‘safety first’ attitude, the operation was concluded successfully and met its said objectives. The successful massive undertaking of such critical well intervention operation has marked a new milestone in rigless well interventions.

The Oil and Gas (O&G) industry is, by its nature, a high risk industry and poses risks to both staff and workers if appropriate controls are not in place. Failures in implementation of well control safe operating systems have resulted in incidents of varying nature, fires, loss of containment and damage to the environment. A root cause analysis of 6 well control incidents occurred between 2010 and 2014 was conducted and gaps in implementation of expectations of HSE management system identified. A process of embedding learning from incident was developed and linked with 2015 action plan. To prevent well control events, identification of barriers (mechanical, procedural and human) were identified and a process was instituted to strengthen these barriers.

This paper was prepared for presentation at the 1999 SPE Offshore Europe Conference held in Aberdeen, Scotland, 7–9 September 1999.

A dynamic integrated thermal and hydraulic model has been integrated into a lifecycle simulation system and utilized for a number of challenging well projects (HPHT, MPD and DGD projects). The model allows for single phase and multiphase modelling and thus also well control modelling. The model has been utilized in planning, training and also during real time operations for decision support. A sophisticated user interface including 3D Visualization of the well has been developed. This has been used to update the risk picture in real time, and communicate this to involved parties. The same advanced model has been built into a planning system; a downhole training simulator and a real time system. The real time model can be used in either a control mode or a supervisory mode. In the control mode the real time model has been used for maintaining constant bottomhole pressure with automatic choke control. During operation a real-time link was established with the rig, and WITSML data in addition to all well, fluid and string data was streamed into a dynamic, real-time simulation system. This simulation system provided the following; i) RT dynamic modelling of the pressure (ECD) and temperature profile in the wellbore; the cuttings distribution and its effects on the ECD; ii) Automatic look-ahead simulations of ECD and temperatures on the fly; iii) RT profiles of simulated versus measured pressure at the PWD, and simulated versus measured standpipe pressure; and iv) RT dynamically updated 3D Visualization of the downhole wellbore with a continuously updated risk picture made available for the drilling teams. This paper will present the model and results of its use in HPHT, MPD and DGD projects.

Drilling through total loss zones without returns at surface is a common practice for Operating Companies in the Middle East. This is known as the Mud Cap/Blind Drilling technique and it has been used for a long time in the region. The lessons learned throughout these years have produced well established procedures and "rules of thumb" for estimating mud density, volume and pumping schedule of the mud cap for different situations. The application of this Mud Cap/Blind Drilling technique becomes more challenging when drilling through oil reservoirs with a high H 2 S content and combining zones with pressure regimes significantly different in the same hole section. This situation is often the case for some well designs commonly used to re-enter oil producer wells in Saudi Arabia. Under these circumstances, the main well control strategy is to maintain enough of a mud cap to prevent any migration of the hazardous gases and/or liquid hydrocarbons to the surface. This approach often results in a conservative design of mud cap densities and volumes, which in turn generates huge expenditures in mud material and puts tremendous stress on logistics and transportation. The Pressurized Mud Cap technique offers a safe alternative to Blind Drilling. This technique uses regular Managed Pressure Drilling (MPD) equipment to monitor the behavior of the reservoir at all times, improving the safety of the operation, by having accurate well control and realizing substantial cost savings, by optimizing the usage of drilling fluid materials and other resources associated with the mixing and pumping of the mud cap. This paper describes the successful implementation of this technique for re-entering oil wells in an onshore field in Saudi Arabia. The paper also provides details for the equipment and procedures utilized to maintain a full column of fluid under pressure, by keeping the MPD choke fully closed while drilling without any returns at the surface. The results, when compared with the conventional Mud Cap/Blind Drilling Technique, show significant improvements in safety (well control), cost efficiency and logistics.

For ultra-deepwater wells, the ability to control and plug the blowout well is more and more important as regulatory agency has more strict rules to issue a drill permit. After the blowout well is killed, cement plugs need to be placed in the borehole to prevent migration of fluids between the different formations. Because of the mixing and contamination process of the cement slurry pumping through relief well, to ensure required cement height and good quality for blowout well, is more challenging than the topside intervention well plugging operations. In this study, dynamic simulations are carried out to assess the difficulties faced during blowout well control and abandonment. In the selected scenarios, the capping stack system is installed on the wellhead of the blowout well and three vessels are used to capture the oil with risers connected to each vessel separately. Through the relief well, sea water is pumped to the blowout well, increasing the hydrostatic pressure and reducing the rate of production. The injection of sea water together with the manipulation of choke outlet pressures on the vessels provides proper conditions for controlling the blowout well, keeping the liquid flow rates within the limits imposed by the processing capacity at surface. As sea water accumulates in the blowout well, reducing oil production rate, each vessel is shut down accordingly. Once the blowout well is completely filled up with sea water, kill mud is used to replace sea water to ensure static kill. Cement slurry is then pumped to blowout well to set the cement plug. The displacement is specially studied when the cement slurry is flowing into the blowout well. In the sensitivity analysis, borehole enlargement, cement slurry rheology, and flow rate are considered to investigate the contamination of the cement slurry. The presented outcomes allow engineers to better understand the operation procedures for blowout well control with capping, containment and zero discharge to the environment under capping and containment scenario after worst case discharge, and the methods to mitigate cement slurry contamination and ensure good cement plug for well abandonment.

Well control is primarily achieved using mud hydrostatic column to overbalance reservoir pressures. The overbalance from mud can be lost in a well due to following reasons; encountering unexpected higher pore pressure, reduction in mud column due to down hole losses, reduction in mud weight due to dilution and loss of hydrostatic head due to poor drilling practices. Emergency situation is created when escalation of any of the scenarios results to the loss of primary well control. In such instance, the secondary well control equipment such as blow out preventers and wellheads are activated to enable restoration of overbalance and return of drilling operation to normalcy. As part of emergency preparedness, it is important to regularly confirm the pressure integrity of the secondary well control equipment in order to guarantee their availability whenever required. As part of the pressure integrity assurance process in Shell operations, pressure test of the critical equipment is mandatorily carried out every 21days whenever the wellbore is exposed to hydrocarbon bearing reservoir. Drilling operation has been successfully carried on GXH-1 HPHT well across the hydrocarbon bearing hydrostatic interval. Pressure test that was carried out on the well control equipment after installing the 9 7/8″ production casing and prior to drilling into the high pressure interval of the well revealed loss of pressure integrity at the flange connection between the 15,000psi rated BOP and fastlock drilling adapter on the 15,000psi rated wellhead. Upon observation, the loss of pressure integrity was discovered to be due to washout on the flanges of the BOPs and the wellhead as well as the ring gasket. The well was suspended with plug to allow safe repairs of the damaged flanges. The damages on the flanges were successfully repaired and pressure tested to full rated working pressure before recommencement of drilling operation. This paper reviews the relevant drilling operations that preceded the loss of pressure integrity of the secondary well control equipment and the root cause analysis carried out on the failure. It also enumerates recommendations from lessons learnt from the incident that will ensure prevention of future re-occurrence of the type of failure.

The conventional methods of oil and gas wells drilling has been to keep drilling mud in the active mud pit at ambient temperature and pressure to drill oil and gas wells; despite the effect of temperature and pressure on mud properties at bottom hole condition. Although, this practice has proved to be adequate in shallow and conventional wells owing to relatively small difference in temperature between surface and bottom hole and the existence of sufficient margin between pore and fracture pressures. Conversely, lots of changes occur on mud properties especially in drilling High Pressure High Temperature (HPHT) wells leading to increased incidences and serious well control situations. One of the key characteristics of HPHT wells is the existence of small margin between pore pressure and fracture pressure as well as elevated bottom hole temperature. This property of the well (HPHT) presents series of challenges to both drilling fluid management at bottom hole condition and well control incidents. Literature survey puts well control incident rate for conventional wells at 4 to 5% whereas in non-conventional wells such as the HPHT wells, an alarming rate of 100 to 200% or even greater has been recorded. This represents at least one well control incident in every 20 to 25 wells drilled for conventional wells and at least one to two well control incidents for every non-conventional well like HPHT. In this study, tier I HPHT well was examined to ascertain the severity of kick intensity and kick volume on well control using Drill Bench. Simulations were performed on 6.5bbls and 1bbls kick taken in 12¼” hole prior to reaching the next casing seat at 13780ft-ss TVD. The research presents results of delay in shut-in the well, kick volume and volume development during well control as well as gas migration. In addition, the study examined implication of well control methods and drilling fluid type on bottom hole pressures and timing to handle well control incident during HPHT well drilling.