Using the right drilling fluid with optimal rheology and filtration properties is one of the most important factors in successful drilling and completion operations. Designing the right drilling fluid depends on a variety of factors viz. formation lithology, wellbore geometry, temperature, pressure, and drilling objectives. To the best of the author's knowledge there is no standard drilling fluid advisory system to aid drilling engineers and scientists to formulate effective drilling fluids systems for the entire well sections. The paper describes a drilling fluid advisory system based on Artificial Bayesian Intelligence. The advisory system includes a Bayesian decision network (BDN) model that receives inputs and outputs recommendations based on Bayesian probability determinations. This advisory system has been designed to aid drilling engineers when designing drilling fluids for their operations. This paper describes a module that was created in this advisory system. This module was created based on several inputs viz. well geometry (vertical and horizontal), temperature, pressure, productivity. To create the drilling fluids module within the advisory system, a number of drilling fluid specialists/experts were interviewed to gather the information required to determine the best practices as a function of the above inputs. These best practices were then used to build decision trees that would allow the user to take an elementary data set and end up with a decision that honors the best practices. The designing process of this advisory system also included a number of standard lab tests that start from quality assurance, initial designing and finally using field samples to confirm the success of the application. The study also discusses several field cases that validate the drilling fluids advisory system. The novel drilling fluid advisory system based on Artificial Bayesian Intelligence has been designed to aid drilling engineers and scientists to formulate effective drilling fluids systems for the entire well sections.

Shale swelling and hydration during the drilling operation have adverse effects on the stability of a wellbore. Hydrophilic interactions of shale results in swelling and disintegration of the shale formation. This paper discusses wettability changes and hydration characteristics of shale to improve the wellbore stability. The use of multibranched ionic liquid as drilling fluid for high temperature applications was investigated. The novel multibranched ionic liquid (Trihexyltetradecyl phosphonium bis (2,4,4-trimethyl pentyl) phosphinate, denoted as Tpb-P) water-based drilling fluid was prepared by mixing different concentrations of ionic liquid and other additives such as filtration controller, rheological modifier, and pH controller. The wettability of bentonite powder was determined using a contact angle in the presence of various concentrations of ionic liquids. Several other experimental techniques, such as linear swelling, hot rolling recovery, and bentonite swell index, were used to examine the inhibition performance of ionic liquid. The rheology and filtration properties of ionic liquid-based drilling fluid were also examined. Various concentrations of multibranched ionic liquid were used to formulate the drilling fluids ranging from (0.1 to 0.5 wt.%), and their performances were compared with the base drilling fluid prepared without ionic liquid. The hydrophobicity of the shale surface was determined by measuring the contact angle, and results showed that drilling fluid having 0.1 wt.% concentration of ionic liquid has a maximum contact angle indicating the highly hydrophobic shale surface. The hot rolling shale recovery experiment was conducted at 150°F, and it was observed that adding ionic liquid improved the shale recovery (24.4%) compared to the base fluid recovery (12.8%). The linear swelling was evaluated over the time of 24 hours, and the least swelling of bentonite was noticed with 0.1 wt.% ionic liquid (98.1%) compared to linear swelling in deionized water (125%). The results suggested that the ionic liquid in the drilling fluid chemically interacted with the clay surface and reduced the hydrophilicity of clay, which restricts the exchange of water onto the clay surface.

Horizontal sections drilled in conditions that require high mud densities to prevent wellbore collapse are very challenging from both drilling engineering and drilling fluid management point of views. Due to drilling complications, nonaqueous fluids (NAFs) are the best suitable drilling fluids of choice for drilling complex and long horizontal sections. From the other side, as nonacid soluble weighting materials cannot be used while drilling some reservoir sections, which are completed with open screens in open hole, using calcium carbonate is the most economical and best preferred acid soluble/nondamaging option to formulate these fluids. When the density requirements reach above 90 lb/ft3 (12 lb/gal) while using calcium carbonate in the NAFs, fluid formulations exhibit high rheological values due to excessive solids. High solids loading and improper fluids engineering in these high-density ranges lead to hole instability and differential sticking issues in addition to extreme difficulties in managing completions screens runs. These challenges can severely limit the well depth or increase the operation time, impacting profitability of whole project; failing to tackle even one of them could result in catastrophic failure. To overcome above associated challenges, a flexible novel flat rheology invert emulsion system formulation was introduced, which was customized for sustaining high solids loading while maintaining its signature flat-rheology profile. This system uses new technology emulsifier and rheology modifier package for achieving flat-rheology independent of temperature and pressure changes. The fluid formulation was implemented in the area by loading the mud system with more than 330 pounds per barrel of calcium carbonate for reaching densities up to 99 lb/ft3 (13.25 lb/gal). This paper will present a comprehensive overview of novel technology, the steps taken from planning to execution, the overall performance-based results, the cost effectiveness of the new solution, and the challenges during implementation. The troubleshooting steps taken are also discussed for all the challenges that occurred while drilling.

A Major Operating Company in UAE planned and drilled a challenging 6 inch horizontal drain after crossing twenty-seven formation sub-layers. The heterogeneity of pore pressure varied from equivalent mud weights as high as 10.6 ppg to as low as 7.1 ppg across the exposed reservoirs. Control of the equivalent circulating density (ECD) values to safely drill across these multi-reservoir sections and diverse reservoir pressures was one of the top challenges on this well, as the fracture gradients (FG) ranged from 13.5 ppg across the competent reservoirs to as low as 11ppg across the fractured reservoir section. The offset well data review show that 4 out of 6 wells encountered moderate, severe and total losses with mud weight (MW) ranging from 11 ppg to 11.3 ppg, which were cured by using heavy LCM treatments and in some cases, after several failed attempts to cure losses, cement plugs were used. Historically, the average time spent curing total losses in these wells varied from 2-3.5 weeks causing well cost increments as consequence of this non-productive time. All of the above, without mentioning the extra efforts, resources and risks were faced due to well control and stuck pipe events which occurred on those wells. Engineering and Operation teams worked together to engineer a solution to drill this well in one run while safely maintaining the well under control and managing the losses. The Bottom Hole Assembly (BHA) was designed to withstand the well challenges including multiple contingency options. These options allowed: Improving hole quality while tripping using a special type of eccentric reamer stabilizer. Pumping various LCM concentration scenarios through a multi-cycle circulation valve. In addition, a special type of float valve was placed on the top of the BHA as barrier, stopping back flow under surface backpressure or kick scenarios. Optimizing mud weight by using formation pressure while drilling (FPWD) and monitoring both equivalent circulating density ECD and equivalent static density (ESD) by pressure while drilling tools. The drilling fluid was loaded with non-damaging loss circulation material without compromising the MWD/LWD limits. Additionally, the mud rheology was carefully selected and monitored to achieve the desired ECD. On surface, a managed pressure while drilling system was deployed to give control on reservoir pressures. In instances of influx, MPD allows to early detect any kick and controlled by surface back pressure without requiring shut in for applying standard well control techniques. Keeping the well under control by surface back pressure (SBP) during connections time (flow–off). Additionally, MPD also enables the contingency of applying pressurized mud capping in case of unable to control the losses. As decision point, a loss management plan was prepared and implemented. Also, a dynamic formation integrity test was planned and performed to calibrate the fracture gradient across the loss zones. The problematic zone was successfully drilled with one BHA in under six days (5.73 days). The estimated savings for the company were 8 days, which equates to ±1MMUS$ after including the MPD cost which increased the well cost by 200MUS$. To further complement the outright savings, the engineered solution managed to safely stave off operational complications as well as incurring the related complexities and non-productive time (NPT) as recorded on the offset wells. Additionally, well was successfully landed and geo-steered across the target formation and 4½ in liner was run and cemented off-bottom avoiding the need to develop a slot recovery scope on this well with an extra duration of +/-35 days. The engineered solution provided a high level of preparation and contingencies within the BHA, Managed Pressure Drilling Equipment, real time monitoring, mud and cement formulation. The applied techniques allowed the operating company to successfully execute this challenge well within the proposed time and budget.

The paper will present lessons learnt to mitigate the stabilization of the air/gas entering into lubricious biopolymer water-based system which decreased density of mud while drilling. The system selected for its highly lubricious properties and formation damage free properties to accommodate the usage of resistivity equipment provided excellent results in the field. Performance was almost equivalent to non-aqueous drilling fluid. However, the stabilization of gas/air entering the mud was encountered generating drilling troubles and risk of well control problems. An extensive study performed, consisted of assessing interactions between components and containments of the mud system with gas/air, crude-oil and drill solids introduced from the reservoir. The testing involved the adding of air from air-compressor for 60-second while mud sample is sheared at 6000 rpm. The mud weights of samples were measured before addition of air, right after and 60-second after the aeration. The percentage of density drop was calculated. Target value was maximum drop of 5% within 60 second after stopping the addition of air. Several combinations of polymers, lubricants, contaminants and other additives were evaluated. The study demonstrated that the interactions between crude-oil, polymers and lubricants can highly stabilize air/gas entrapment in the biopolymer water base mud system. The phenomena led to significant density decrease, drilling troubles, well control and safety issue in the field. They can also increase the viscosity of the biopolymer mud system. However, highly stabilized air/gas entrapment can be removed by the addition of emulsion breaker at concentration less than 1.5%vol of mud. In addition, the type and nature of the lubricant plays a major role in the stabilization of air/gas entrapment. The selection of the polymers should be combined with the choice of lubricant during the design phase to minimize the gas entrapment. Knowledge gained from the study establish a new testing protocol to assess in the laboratory the air/gas entrapment close to field shear conditions. The testing protocol showed good correlation with the field. The testing protocol can be used during the design phase or for investigations. It will improve the overall design of mud system where highly lubricious fluid is needed. Combination of polymers and lubricants did also provide low air/gas entrapment tendency.

The present paper describes the results of the formulation of an acid-soluble low ECD organoclay-free invert emulsion drilling fluid formulated with acid soluble manganese tetroxide and a specially designed bridging package. The paper also presents a short summary of field applications to date. The novel, non-damaging fluid has superior rheology resulting in lower ECD, excellent suspension properties for effective hole cleaning and barite-sag resistance while also reducing the risk of stuck pipe in high over balance applications. 95pcf high performance invert emulsion fluid (HPIEF) was formulated using an engineered bridging package comprising of acid-soluble bridging agents and an acid-soluble weighting agent viz. manganese tetroxide. The paper describes the filtration and rheological properties of the HPIEF after hot rolling at 300 o F. Different tests such as contamination testing, sag-factor analysis, high temperature-high pressure rheology measurements and filter-cake breaking studies at 300 o F were performed on the HPIEF. The 95pcf fluid was also subjected to particle plugging experiments to determine the invasion characteristics and the non-damaging nature of the fluids. The 95pcf HPIEF exhibited optimal filtration properties at high overbalance conditions. The low PV values and rheological profile support low ECDs while drilling. The static aging tests performed on the 95pcf HPIEF resulted in a sag factor of less than 0.53, qualifying the inherent stability for expected downhole conditions. The HPIEF demonstrated resilience to contamination testing with negligible change in properties. Filter-cake breaking experiments performed using a specially designed breaker fluid system gave high filter-cake breaking efficiency. Return permeability studies were performed with the HPIEF against synthetic core material, results of which confirmed the non-damaging design of the fluid. The paper thus demonstrates the superior performance of the HPIEF in achieving the desired lab and field performance.

Developing high-performance environmentally friendly drilling fluids is always a requirement by oil and gas operators to reduce the waste management associated cost with the drilling fluid treatment and disposal. Conventional water-based drilling fluid is formulated with the brine-based polymer which consists of sodium and potassium chloride salts to improve the performance of the polymer and also providing clay inhibition in reactive clay and shale. This paper describes the development of nanotechnology-based drilling fluid to replace salt from the conventional application. Nano Based Low Saline Water Based Mud (NBLS-WBM) was formulated and developed based on laboratory experiments. Different nano additives with different concentrations were evaluated and the optimum concentration was selected to reduce the sodium and potassium chloride salts concentration to almost zero. The rheological properties and fluid loss were measured according to the API standard before and after hot rolling. Also, HPHT fluid loss, lubricity, and shale inhibition were evaluated. All the results were compared with sodium salt-saturated and potassium-based polymer muds. Laboratory evaluation of NBLS-WBM indicated that sodium salt concentration can be reduced considerably up to 5% W/V and potassium chloride can be eliminated by adding 1% W/W of nano additive. The rheological properties including plastic viscosity and yield point were constant and stable after hot rolling 16 hours at 250 °F. Also, Clay inhibition improved significantly up to 95% recovery comparing with conventional water-based polymer mud. Although the application of nanotechnology to improve the performance of conventional water-based drilling fluid was studied by many researchers, it is the novelty of this research to reduce the salt concentration and remove it to develop the new generation of salt-free water-based drilling fluid with economical consideration and lower environmental impact.

During drilling of permeable reservoirs, drilling fluid may penetrate the formation and induce damage to the reservoir rock. Specifically, solids present in the drilling fluid may enter the formation and cause subsequent reduction in reservoir permeability in the area near the wellbore. When drilling with a water-based drilling fluid in a reservoir, various polymer-based additives are normally applied to reduce the filtration loss. These additives, such as Xanthan Gum, Poly Anionic Cellulose (PAC) and Starch may help in reducing losses to the formation in presence of small pore-throats and low differential pressures. If the pore throats exceed e.g. 20μm and differential pressures reach 500psi, these additives have little effect on reducing loss of drilling fluid to the formation and thereby little effect in preventing solids from entering the formation. Lost circulation is particularly challenging when losses occur in the reservoir section. This is because LCM treatment may create formation damages. Green et al. (SPE-185889) showed the nature of drilling fluid invasion, clean-up, and retention during reservoir formation drilling. They also showed the lack of direct relation between fluid loss and formation damage. In light of such ideas, a development of new Non-Invasive Fluid (NIF) additives was conducted. These additives were able to handle downhole pressure differences and create a preventative sealing of a permeable formation when applied into a solids-free drilling fluid. Ceramic discs of various permeability and mean pore-throat size were installed into a HTHP pressure cell. Drilling fluid was pumped through the cell and a filter cake was formed across the ceramic disc. A pressure of 500psi was applied and filtration loss was measured over a 30-minute period. Examples are herein presented showing how filter cake materials were applied into the drilling fluid and effectively sealing the permeable surface of the ceramic disc. Also, it will be shown how the filter cake was effectively removed from the discs using a breaker solution. Furthermore, a selection of experiments is presented, showing the possibility to heal lost circulation in permeable reservoirs without the presence of weighing materials, clays or drill-solids in the drilling fluid. A test was also conducted in such a way that the disc was fractured inside the test cell to investigate the impact on fluid loss.

Drilling in deep high-pressure high-temperature (HPHT) abrasive sandstone pose significant challenges: low rate of penetration (ROP), bit wear, differential sticking, and wellbore instability issues. These issues are magnified when attempting to drill long laterals in the direction of minimum stress. This paper focuses on the use of Managed Pressure Drilling (MPD) and Artificial Intelligence (AI) analytics to improve ROP. MPD is normally used to help drilling in formations with narrow mud weight window, it achieves this by controlling the surface backpressure to keep the annular pressure in the wellbore above the pore pressure and below the fracture gradient. One key benefit of using MPD is that high mud weight is no longer required, since the Equivalent Circulating Density (ECD) is going to be managed to maintain the overbalance. An example of a well that was drilled using MPD solely for ROP improvement is presented in this paper. This well achieved almost double the ROP of a control well, which was drilled in the same formation with no MPD. Essentially most of the drilling parameters used, which include, pump rate, revolution per minute (RPM), weight on bit (WOB), and other drilling practices, are controlled by the people on the rig. Incorporating AI analytics in the equation, help minimizes human intervention and could achieve further improvement in ROP. After the ROP improvement observed while using MPD, both technologies were combined in a well drilling the same formation. An example is presented for the well drilled using both technologies.

The success or failure of cement plugs are known to alter the timeline of an oil well; not to mention the additional costs and NPT associated with the rig activities. Unsuccessful cement plug costs oil companies considerable amount of capital both in extra rig time and service company expenses. Suggested procedures for placing cement plugs have been presented in number of papers - comprising of slurry design, spacer recommendations, laboratory testing and placement techniques. However, it is very easy to deviate from these standard practices due to over confidence, negligence or both. In Mexico, it was observed that the success rate of placing cement plugs dropped due to operational and engineering design shortcomings. Towards the end of 2018 there were several unsuccessful cement plug jobs that questioned the regular plug procedures. Careful analysis of the past mistakes led to the conclusion that an effective approach to alter the local plug placement practices was necessary. An updated cement plug placement software was used in conjunction with strict standard practices that turned around the trend and enabled consistent successful placement of cement plugs in the first attempt itself. A detailed yet simple approach towards cement plugs was adopted in both engineering design and operational execution. Additionally the updated plug placement software ensured accurate prediction of the cement plug top; that was confirmed by the actual tag of the plug. This paper will enlist the major analysis carried out on the unsuccessful plug jobs and highlight the different techniques that were adopted in the subsequent jobs to ensure successful placement and tagging of the cement plug. The paper will also focus on how the plug placement software's new additional features have made a significant contribution to this success story.

On a Deep Gas Field in the Middle East, it is required to drill across a highly fractured and faulted carbonate formation. In most wells drilled across the flank of this field, it is impossible to cure the encountered losses with conventional or engineered solutions. Average time to cure losses is 20 days. With the current drive for cost optimization, it has become necessary to eliminate the NPT associated with curing the losses. A thorough risk assessment was conducted for wells drilled on the flank of this field, it was established that the risk of encountering total losses was very high. Seismic studies were performed and it was observed it would be impossible to eliminate total losses as fractures were propagated in all directions. It was proposed to run a sacrificial open hole bridge plug above the loss zone and sidetrack the well instead of performing extensive remedial operations. The proposed solution would help eliminate the well control and HSE risks associated with drilling blindly ahead with the reservoir formation exposed. Applied the proposed solution on the next well that was drilled on the flank of the field, encountered total losses, spotted eight LCM pills, unable to cure the losses, ran sacrificial open hole bridge plug and sidetracked the well. The entire process was completed in 30 hours. Sidetracked the well in adjacent direction to the initial planned well trajectory based on further seismic data analysis and no losses was encountered. Recovered full mud column to surface thus ensuring the restoration of all well barrier elements. This solution has since been adopted as best practice for wells drilled on the flank of the field where there is high probability of encountering total losses. The average time saving per well due to this optimized solution is 450 hours for wells where total losses are encountered. This engineered solution has made drilling wells on the flank of the field in a timely manner possible and at optimized costs. This has resulted in: – The elimination of Non-Productive Time, – Quick delivery of the well to production, – Reduced HSE risk, – Reduced well control risk as loss zone is quickly isolated before drilling ahead. This paper will explain why running sacrificial open hole bridge plugs and sidetracking the well is a more effective solution compared to extended remedial operations when total losses are encountered while drilling across highly fractured / faulted formation. It will discuss the extensive risk assessment conducted, the mitigation and prevention measures that were put in place in order to ensure successful implementation on trial well.

Over the last 60 years, Abu Dhabi, United Arab Emirates (UAE) has been producing oil and gas from different conventional fields. Nowadays, and as part of the State long-term strategy to achieve the nation objective of gas self-sufficiency, it has been decided to explore, appraise and develop unconventional plays in the Northern area including the construction of early production facilities to supply the gas power plants. Three wells were drilled as part of the first phase of the project; consisting of a pilot hole into an extremely heterogeneous formation; two of them were horizontalized into the targeted formations. The first well across the salt represented a tremendous challenge due to limited rig capacity generating hole stability issues that required unplanned remedial jobs. The second well was deviated across the salt as pilot hole, then side-tracked and horizontalized in the targeted reservoirs. The third well was drilled directly as horizontal lateral based on previous lessons learned validating the horizontal concept for the future field development plan. The exploration phase constituted by these three wells, were drilled and completed successfully. A detailed data gathering program was executed allowing mapping of the area validating the presence of gas. The drilling parameters, such as rate of penetration (ROP) for the horizontal section was enhanced by optimizing the drilling Bit design. The mud logging results have confirmed the extremely heterogeneous formations across this section allowing determining the most fit for purpose bottom hole assembly (BHA); obtained after a detailed optimization process. Multiple lessons learned were captured and immediately applied leading to a significant reduction on total days per well that reflected on an outstanding cost reduction including rig move optimization, incrementing the overall efficiency of the operations. This project has proven the potential of unlocking the development of this field focusing on the targeted untapped reservoirs. Key unprecedented achievements have been fulfilled during the execution of this phase of the project: 1. First time to drill across a salt dome in Abu Dhabi Emirate 2. First time that horizontalization has been applied to the targeted formations. In addition, a better understanding of the optimum drilling parameters for future phases has been obtained.

High-temperature water-based drilling fluid systems hold several advantages over synthetic based systems from financial and environmental viewpoints. However, most conventional water-based systems start to become unstable at temperatures above 300 degF. This paper details the design and implementation of A Novel Water-Based Drilling Fluid that meet these temperature stability requirements. The newly developed high-temperature water-based system discussed in this paper utilizes a custom-made branched synthetic polymer that exhibits superior rheological properties and fluid loss control as well as long term stability above 400 degF. The branched synthetic polymer is compatible with most oilfield brines and maintains excellent low-end rheology necessary for hole cleaning and solids suspension under high-temperatures and pressures. Under static conditions, the high-temperature fluid shows no gelation resulting in lower swab surge pressures while the stability of the highly branched synthetic polymer and enhanced rheological profile minimize sag. To drill a challenging exploration well, a Middle East client required a cost-effective drilling fluid system which remains stable under static temperatures expected to exceed 375 degF. The long-term stability of the system was critical for successful wireline logging operations. In addition, the system was required to provide shale inhibition, hydrogen sulfide suppression and sufficient density (above 16.5 lbm/galUS) to maintain well integrity while drilling through anticipated high-pressure zones. The challenging intermediate (12.25-in and 8.375-in) and reservoir (6-in) sections were successfully drilled and evaluated using this new branched synthetic polymer-based system. Fluid property trends and system treatments will be detailed alongside thermal stability data for extended periods required for wireline logging (up to 9 days static). This paper will discuss how proper laboratory design of the high-temperature water-based system was translated to excellent field performance and will indicate how this technology can be utilized for future campaigns in the region and worldwide.

Horizontal well drilling contribute to a dramatic increase of shale gas production in unconventional reservoirs. However, the drilling is also risky and challenging with different types of drilling problems often encountered including stuck pipes, inflows, losses and pack-offs, etc. To reduce shale-gas development costs, shale gas operators are faced with finding effective solutions to minimize drilling risks and improve drilling efficiency. A holistic workflow, which can be divided into three steps: pre-drilled modelling and assessment, real-time monitoring, and post-drilled validation, is proposed. Based on the pre-drilled geomechanical modeling, mud weights, mud formulations and casing setting depths are optimized to ensure wellbore stability during the drilling process. Real-time operations involve monitoring drilling parameters and cavings characteristics (shape and volume), and providing updated recommendations for field drilling engineers to mitigate and reduce borehole instability related problems. During the post-drilled stage, the updated geomechanical model will be used for optimizing the drilling designs of upcoming wells. With geomechanics as foundation, a systematic workflow was developed to provide integrated solutions by using multiple technologies and services to reduce serious wellbore instability caused by abnormal formation pressures, wellbore collapse and other complex drilling problems. The implementation of the systematic and holistic workflow has proven to be extremely successful in supporting the drilling of shale gas wells in China. The integrated approach, which was applied in a Changning shale gas block in Sichuan Basin for the first time in March 2019, recorded an improvement in ROP by 111.2% and a reduction in mud losses by 89.9% compared with an offset well without the risk mitigation strategy applied in the same pad. The geomechanics-based approach provides a convenient and effective means to assist field engineers in mud weight optimization, drilling risk assessments, and horizontal well drilling performance evaluation. The approach can also be extended to reduce potential drilling risks and improve wellbore stability, all of which contributes to reducing drilling costs and optimizing subsequent massive hydraulic fracturing jobs.

Cementing a highly deviated production liner is associated with cement placement challenge that can compromise zonal isolation. A major operator in UAE, was facing a challenge to cement 4 ½ in slim production liner set at + 5000 ft off-bottom. The corresponding 6 in. section was drilled with a relatively high mud weight in the range of 12 to 13 PPG. One of the main challenge was the risk of solids settling on the low side of the wellbore, making mud displacement difficult to achieve while cementing. Additionally, cementing off-bottom without an ECP in a highly deviated wellbore with multiple exposed production zones, further increased cement placement complexity. A holistic engineering approach was integrated to ensure successful zonal isolation. Wellbore parameters and fluid properties were critically evaluated. To overcome off-bottom cementing and prevent slurry fallback risks, a weighted high viscosity pill with high yield point was placed as a temporary basement to support the cement column and isolate the reservoir during 4 ½ in liner job. After placement of the pill, the wellbore was observed for flow checks to ensure stable downhole conditions prior to displacing the drilling fluid across the liner interval to brine within the same density. A centralization program was implemented to achieve more than 70% stand-off which required a minimum centralization pattern of two rigid centralizers per joint which helped minimize the presence of mud channels on the narrow side. Effective mud removal was ensured through implementation of a spacer train in front of the cement. The first spacer was pumped with same mud density to reduce ECD followed by another advanced low invasion loss circulation spacer to mitigate losses as well as provide a sustained downhole rheology. A resilient, expandable and gas tight cement slurry, was selected to target long-term zonal isolation. Multiple hydraulic simulations were performed to optimize ECDs and ensure safe margins during placement A CFD (computational fluid dynamics) model was utilized to simulate hydraulics, expected mud removal and fluids inter-mixing especially during liner rotation. In addition, the model simulated high-calculated torques based on flow restrictions through liner hanger assembly. Lack of mechanical liner movement was compensated by additional pre-job circulation to fully condition the wellbore. The job was executed with no losses during cementing, and spacer and cement returns were received on the surface during reverse out. Utilizing the best engineering approach, practices, and techniques from this job is implemented in the future wells as the production of the well is directly affected by the cement quality. Post job cement integrity evaluation via a cement bond log confirmed excellent bonding of cement to the liner and reservoirs across the entire open-hole interval.

This paper presents a rigorous, mechanistic model for simulating a gas kick, that uses the thermodynamic approach to account for gas solubility. This thermodynamic solubility model uses the pressure and temperature data from the kick simulations and estimates the mole fraction of various gas components in the liquid phase. We validated these gas solubility results using Aspen HYSYS, a commercial chemical process simulation software. The thermodynamic solubility model presented in this paper assumes a pure-methane kick and applies the concepts of phase-equilibrium and fugacity to estimate the amount of dissolved gas in the drilling fluid. Application of fugacity equilibrium between the gas and liquid phases, in conjunction with the Peng-Robinson equation, gives the liquid phase mole fraction of methane. The analytical kick model uses the Hasan-Kabir two-phase flow modeling approach to describes the changes in pressure during kick migration, at various points in the annulus. Since the expansion of the gas bubbles depends on the variation in pressure, these studies also lead to pit gain estimates. A comparison between our model results and HYSYS values for methane liquid-phase mole fraction showed a maximum 8% deviation with complete agreement on bubble point (P b ) pressure and location estimates. Similarly, our model calculated the solution gas-oil ratio (R s ), with a maximum divergence of 3% from HYSYS estimates. From the comparison studies with other empirical B o & R s correlations, we note that the estimates of our model agreed best with those of O’Bryan’s ( O'Bryan 1988 ) correlations. Many numerical kick simulators exist today, but they are notoriously time-consuming, limiting their on-field utility. Our kick simulator’s simplicity makes it potentially useful for on-field well control decisions. Most of these existing numerical simulators ignore the effects of kick solubility in synthetic-based muds. In the few models that do not ignore solubility, the approach to accounting for gas solubility and mud swelling is empirical, limiting their usage under conditions beyond the range of the source data used in developing these correlations. The mud swelling calculation approach we developed does not have these pressure and temperature range limitations.

Maintaining the integrity of the drilling-fluid column is vital for safety and operational efficiency. Stable, controlled fluid density provides a primary pressure barrier during the drilling phase. Non-aqueous fluids (NAFs) provide huge benefits for nearly all aspects of difficult drilling situations, yet still can have challenges related to weight suspension. The geometry and annular restrictions of modern well designs often demand low fluid rheology parameters to avoid excessive circulating pressures, and this unsurprisingly increases the risks of sagging weight material. Given the importance of understanding the fluid behaviors in these situations, operators and service companies have made significant efforts to develop reliable sag testing methods. Older methods of testing neglected movement and instead centered on mimicking the downhole conditions such as temperature and hydrostatic pressure. Variations of this static aging method addressed the critical angle where Boycott settling accelerates the sag. More complex, dynamic methods were devised later in time to provide greater insight on sag behaviors. Although engineers and scientists have made numerous strides to create a definitive sag test, the current tests have limited capabilities. Very few are capable of working in an offshore environment. Sag events continue to be costly and problematic to operators’ main objectives of drilling and completing their wells safely and efficiently. The authors address results from the current state of the art in sag testing and compare these to a proprietary dynamic procedure created in 2019. While the method is still in development, its capabilities have been well defined. Fluid samples are kept in constant motion at low-ranging shear rates and elevated temperatures to simulate sag-prone conditions downhole. Results indicate a high degree of correlation to the expected sag with different sizes of barite in low-ECD fluids.

Reservoir sections in MRC (Maximum Reservoir Contact) & ERD (Extended Reach Drilling) wells are mainly designed to drill 8 ½" hole, because of drilling limitations with smaller hole size. However, slim hole sizes offer opportunities to revitalize existing wells using re-entry drilling techniques in association with MRC and ERD designs. This paper discusses the best practices to be implemented in order to mitigate risk, reduce complexity and ensure improved drilling performance. Re-Entry wells in the field have a risk of well integrity issues such as corroded 9 5/8" casing. In order to mitigate this risk, the corroded 9 5/8" casing should be covered by 7" liner & tied-back to surface before drilling reservoir section. In this situation up to 18,000 ft of 4" DP is used in the wells to drill 6" hole and run 4 ½" lower completion. Offset well analysis, whip stock selection criteria, BHA design, drilling fluid selection, drilling and tripping practices based on torque & drag and hydraulics calculations are most important to achieve the well objective. The Slim hole MRC well was completed without any issues and achieved good drilling performance. It was observed that the actual drilling parameters such as torque, drag and stand pipe pressure were less than simulated parameters. NAF was selected in the section to reduce the friction factor, while motorized RSS and a reamer stabilizer were used in the BHA to reduce torque, drag and ensure a smooth well profile. A back reaming practice was implemented in hole section to reduce dog leg severity and the open hole was eventually displaced to viscosified brine to minimize the friction factor for running the 4 ½' lower completion. 8500 ft of 6" hole section was drilled and TD was reached at +/- 19,000ft within 50 days including recovering the existing completion, drilling 8 ½" & 6" hole and running completion. This paper aims to contribute to the oilfield industry by sharing the successfully implemented engineering design and operation execution methodology to overcome the complexities present in Re Entry Wells MRC/ERD wells required to be drilled with slim hole conditions under an optimal cost, time effectiveness and low risk.

Due to high temperature, high pressure, and gypsum-salt formations in the Tian Mountain Front Block in Tarim Basin, the stability and rheology of traditional polymer drilling fluids are difficult to maintain, so sulfonated drilling fluids (SDF) are recommended to drill deep formations. The sulfonated drilling fluids can provide a powerful technical support for achieving high quality drilling, and it has been run for above 200 wells in the past year. However, a large number of sulfonated drilling cuttings are generated in the drilling operation. These drilling cuttings contain a large number of harmful substances, including petroleum hydrocarbon, sulfonated additives, soluble salts, and so on, which are toxic and difficult to be biodegradable, so the discharge of drilling cuttings into environment will lead to serious contamination of soil and groundwater. Conventional drilling cuttings treatment methods, include reinjection method, solidification with cement method, and chemical desorption method, have several disadvantages such as low efficiency, high cost, or recontamination, and they could not recycle any useful resource, so they are not applicable for large-scale treatment of sulfonated drilling cuttings. Innovative high temperature deep pyrolysis technology (HDPT) is currently developed to treat sulfonated drilling cuttings. HDPT consists of cuttings drying system, high temperature pyrolysis system and waste gas treatment system. By using of high temperature pyrolysis system, harmful organic compounds in drilling cuttings could be completely degraded. Owing to complete isolation between drilling cuttings and flames, nitrogen oxides and other harmful substances could be effectively avoided to produce. Then the obtained acidic gases, such as sulfur dioxide, hydrogen chloride, chlorine, and so on, could be rapidly eliminated by waste gas treatment system. The drilling cuttings, barite agent and waste gas could be obtained. The field results indicate that the content of petroleum hydrocarbon of obtained drilling cuttings is less than 16 ppm, and various indexes of obtained drilling cuttings could meet the requirement of environmental protection, so these drilling cuttings can be used to pave the road. The recyclable barite agent could be reused to prepare mud. The waste gas could be directly released into the atmosphere. HDPT technology is characterized by high treatment efficiency and no secondary pollution, and it is very suitable for harmless treatment of sulfonated drilling cuttings. HDPT technology can not only guard against environmental pollution from sulfonated drilling fluids, but also recycle and reuse useful resources, and thus produce great environmental and economic benefits. HDPT treatment plant has been built in this Block, and its handling capacity can be up to 1000 kiloliters per day. HDPT technology has been successfully run for treating sulfonated drilling cuttings from dozens of wells, and provides a strong technical support for cleaning production of drilling operation. This paper presents field data to illustrate the application of this technology and evaluate the potential technical and economic benefits that it might provide to petroleum development and production.

When drilling shale formations with water-based drilling fluids, wellbore instability problems arise from the interaction of water with clay minerals. As a result, there will be higher solids loading into the wellbore and the borehole diameter will not be constant along the depth of the well. Hence, the chance to get pipe stuck increases and the hole cleaning efficiency of drilling mud decreases significantly. To combat shale drilling problems, different types of inhibitive water-based muds were developed. The performance and effectiveness to inhibit shale formations vary between one type of shale inhibitors to the other. Oil and gas industry has standard procedures to test the inhibition performance of drilling fluids such as dispersion test and swelling test. This paper builds on that and introduces a method to test the long-term shale inhibition capability of shale inhibitors. Due to the presence of some unique geological conditions, sometimes there is a need to replace a high cost inhibitive mud by a low cost non-inhibitive mud to drill the next formation. If the original inhibition provided by the inhibitive drilling fluid does not last long enough to drill the second zone, the previously drilled inhibitive shale formation starts reacting again with the non-inhibitive drilling fluid leading to various drilling problems. Hence, there is a need for isolation of the reactive shale zone by a casing string before drilling ahead. Inhibitive muds with long-term inhibition potential such as 24 hours or more may eliminate the need of a protective casing for the previously drilled shale formation.