The use of micronized weighting agents, in multiple operations, have become more commonplace over the years, with current applications now going far beyond their targeted original purpose of reducing pressure losses in extended reach wells. This specific case reports the development of a fit for purpose system engineered to tackle multiple challenges such as: limitation in using heavy density brines composed of bromides in an offshore environment; hydrate suppression under Drill Stem Test (DST) conditions; weighting agent sagging control; plugging of downhole tools due to heavy solids loading; proper pressure transmission for downhole tools activation; and formation damage prevention. The operation involved the following steps: 1 - development of a Water-based Micronized Weighting Agent Fluid System (WBMWAFS), laboratory testing, simulation evaluation and testing validation for all target properties; 2 - development of an appropriate DST approach with the usage of a designed set of explosives to minimize formation damage and the interaction of the DST fluid with such cargos; and 3 - the evaluation of the overall system performance in order to validate the integrated approach used to design such solution. The DST results indicated that the WBMWAFS is capable of delivering all the technical requirements for a trouble-free operation, with no significant register of weighting agent sag, hydrates or with any variation in fluid properties, whilst enabling a DST operation that demonstrated a negative skin damage during the clean-up period and no damage associated with the WBMWAFS. The WBMWAFS performance opens the possibility of the application of this type of fluid as a replacement for high-density clear brines in many challenging environments.

Monobore cementation is defined as where a single production tubing size runs from the pay zone all the way to surface and is cemented in place. This type of well design greatly reduce rig time and cost. The challenge however is to achieve a good cement in the annulus as a well barrier and to have a clean internal tubing after the cementing job to allow for successful production of the well. To achieve a clean internal tubing, a distinct bottom and top plugs were used as a means of mechanical separation. For fluids design, mud had to be thinned down prior to the cementing job and, a designed fiber based spacer system was used to physically scrub any mud-film sticking on the tubing walls. The centralizers and cement system were designed to allow for efficient displacement of mud and hence providing good overall placement and top of cement in the tubing-casing annulus. The cement in the annulus will be verified by pressure testing the annulus to 500 psi higher than previous shoe leak-off. This approach was implemented for the campaign of six wells, all designed with 5-1/2in monobore tubing. The bottomhole static temperature (BHST) of the well ranges from 300 to 350°F. The cementing system also had to be designed to cater to the challenge of this field, having CO2 as high as 60%, high temperatures, and a long open hole section that requires isolation and cement to set within a required timeframe. The cementing jobs were validated by no losses or gains during the job, floats holding at the end of the cementing job, differential pressure of cement prior to bumping the plug, density and pump rates executed as planned, accepted pressure test criteria of the annulus, output validation of cement contamination in pipe and annulus based on fluids and final well information. To further validate this system, the cement bond log was also run as part of the evaluation process and the cement log showed that zonal isolation was achieved. After the perforations, the perforation tool was pulled out to surface and the tool looked very clean with no signs of contaminated mud or cement around the tool. We demonstrate how this unique cementing approach can be a solution for the challenges of monobore cementing and one of the biggest problems of monobore cementing in the industry.

This paper will detail the engineering strategies utilized from design and planning stage up to and beyond the field execution stage which resulted in drilling the fastest well in a shallow water field, delivering superior drilling performance and successfully targeting the Upper Miocene (tertiary) reservoir in Mexico. From the 9 wells drilled in this field, the fastest well "Y"-200 was drilled with an average well construction index of 179 m/day when compared to the field average of 54.2 m/day. This shallow water field manifests several specific challenges which include tough drilling conditions, fluid property and hydraulic management, logging constraints and critical selection of casing setting depths. In order to enhance the drilling performance results to lower costs and improve production timelines, the project team performed a deep-dive into the well challenges and engaged with multi disciplinary teams and service providers to brainstorm different design improvements and operational practices. By doing so, the performance accelerates the 6000 to 9000 bbls of initial production estimated per well. The application of these creative engineering ideas proves that change, when applied correctly can really create lasting and proven improvements in drilling performance.

Foam fracturing is an effective method for the development of unconventional reservoirs. However, due to lamellar film, high pressure differences within foam films, and the strong diffusivity of the internal phase, foam is prone to suffering from unstable phenomena such as rupture, drainage, disproportionation, etc., thus leading to uncontrollable foam flow behavior in the tube and formation. In this work, cellulose nanofibrils (CNFs) were used to enhance foam fracturing fluid. The target is not only to obtain a stable foam system, but also to control its rheology, proppant-carrying and leak-off behavior. The stability of the N 2 foam fracturing fluid with CNFs was firstly explored via static tests by measuring its foam volume and liquid drainage. Then, the viscosity of foam fracturing fluids with different foam quality was measured using a tube viscometer under conditions of use, to evaluate the rheology of foam with CNFs. Subsequently, the proppant-carrying capacity was evaluated by observing suspension state of proppants in foam over time. The microscopic images of the foam with proppants were collected to analyze the interaction between bubbles and proppant. Finally, the dynamic filtration behavior and core damage of foam with CNFs were investigated by using a dynamic filtration apparatus. The results of the static tests showed that the stability of foam was significantly enhanced by the addition of CNFs, and the liquid drainage and gas diffusion could be effectively inhibited. Upon foam evolution, bare surfactant foam formed a polyhedral structure rapidly, while the CNFs enhanced foam maintained spherical and dense for a long time. The viscosity of foams with and without cellulose nanofibrils showed a shear thinning behavior. With the addition of CNFs, the viscosity of foam was improved by 3 - 6 times compared with bare surfactant foam and its value was increased with foam quality changing from 60% to 80%. The results of proppant-carrying tests indicated that the proppants suspension in foam was improved obviously as the cellulose nanofibrils were added. For CNFs-stabilized foam, the aqueous film of bubbles became thicker and the mechanical strength of foam structure was improved, thus enhancing the proppant suspension in the foams. Moreover, the filtration control performance of CNFs foam was also improved compared with bare surfactant foam. The filtration coefficient of CNFs foam fracturing fluid decreased with increasing CNFs concentration at a filtration pressure difference of 3 MPa, and core damage was maintained at a relatively low level. Additionally, the filtration coefficient of CNFs-stabilized foam and its core damage could be reduced with the increase of foam quality from 60% to 80%. The stability, rheology, proppant-carrying and dynamic filtration control of foam fracturing fluid enhanced by cellulose nanofibrils were explored in this work. The results show that the addition of CNFs effectively improves the stability of the foam, thus enabling the rheology, proppant-carrying and the dynamic filtration to be well controlled, which provides a high-performance and eco-friendly foam fracturing fluid.

There are many challenges while drilling highly inclined and depleted formations offshore Vietnam that result in various wellbore stability issues such as severe losses, stuck pipe, cavings, tight-hole and pack-offs. These issues may be independent of mud type and can occur when drilling with both oil/synthetic-based and water-based muds. These depleted sections typically consist of sandstones interbedded with claystone & siltstones. Traditionally, the wellbore strengthening fluids solution applied to drill through these sections with synthetic and water-based mud in Vietnam faced limited success. Wellbore strengthening (WBS) is a proven and effective solution especially for narrow-drilling margin and depleted formations. The basic concept of WBS relies on the creation and simultaneous plugging of small fractures with appropriate WBS material. The resulting elevated stress around the wellbore strengthens the borehole by creating an increased hoop stress that leads to an increase in near wellbore stresses. Proprietary modelling software can be used to calculate the pressure induced fracture apertures for wellbore strengthening applications and determine the optimum particle size range to bridge these fractures, allowing fluids to be designed to minimise wellbore instability. This design process was used to optimize material additives to effectively bridge fractures, for wellbore strengthening, and pore throat openings in porous/permeable formations for the prevention of seepage losses and differential sticking. A review of the application procedure identified the optimum method to apply the wellbore strengthening material which would minimise product consumption and reduce well costs. After extensive modelling simulations and testing, this fluid design was applied to drill two challenging wells in Vietnam. This paper presents the process of modelling, based on formation geo-mechanics information, customization and laboratory testing of the fluids design coupled with a successful and economical method of application in the field. Application of this process enabled the operator to drill through the depleted challenging sections with a maximum overbalance pressure of 3,200 psi, conduct logging and coring runs and complete the well at a lower cost and with zero fluids related non-productive time compared to previous wells.

This paper is to explain the optimization of using Modified Shale Inhibitor Water Based Mud (WBM) to drill up to 5,500 ft interval of K-formation reactive shale on South-S Gas Wells. By combining a comprehensive method consists of drilling fluid laboratory test and lessons learned in S area, the optimization was done by determining the amount or concentration of Polyamine & KCl combination, pure Polyamine, Polyamine & NaCl combination, and Pure KCl-Polymer in WBM system as a shale inhibitor. The comparison of shale inhibitor compositions were made by comparing the achieved optimization of drilling fluid program such as drilling time, cost economic, and environment aspect. The basic idea of the WBM optimization was to improve drilling time during drill 5,000 ft footage in 12-1/4" hole section in reactive shale formation as per drilling program. Laboratory test consists of Linear swelling meter with various parameter concentration of Polyamine & KCl combination, pure Polyamine, Polyamine & NACl combination, and Pure KCl-Polymer in WBM system as a shale inhibitor and cation exchange capacity test (CEC or MBT) was done using composite of offset well shale cutting. Experience showed that on 12-1/4" hole section, while facing reactive shale (CEC 18 - 24 meq/100 gr) from K-formation on South-S, modified WBM was proven to eliminate reactive shale issues and lead to budget saving without environmental issues.

Objective/Scope The objective of this paper is to highlight the fact that while in conventional drilling there can sometimes be no mud weight solution for drilling a particular narrow margin section without either exceeding the Leak Off Test value at the shoe, or falling below the Pore Pressure at section TD. In Managed Pressure Drilling (MPD) there is often a range of mud weight solutions that can be used to drill the section, but usually one optimum mud weight that should be used, based on different risk criteria that can be evaluated. The consequences of this are that when using MPD, it could be that the section risks have not been minimised and therefore more risk than necessary has been imported into the methodology. Whereas if all MPD mud weight solutions have been evaluated, together with their associated Surface Back Pressures, and the optimum selection made, then the mitigations can be specially tailored so that the remedial actions to any system failure are clearly planned in advance, reducing the overall risk level of the operation. Methods, Procedures, Process The methodology described in this paper demonstrates the process for choosing the optimal mud weight for drilling any well section using MPD, with worked examples. This process is especially applicable for drilling very narrow margin sections, for example with only 0.2 ppg window between Pore Pressure and Fracture Gradient. By enumerating the safety margins both at the previous casing shoe and at the proposed section TD, or any other point of interest, it is possible to rank the risks of kicks and losses in that section across a range of proposed mud weights and use this information to choose the optimal mud weight. Results, Observations, Conclusions The process of evaluating the options and outcomes of using different mud weights in MPD can not only lead to the best drilling solution for the section, but can also be used as a discussion tool between the drilling team and the subsurface team, to help elucidate the most likely risks to the operation and thereby mitigate those risks in the most appropriate way. Novel/Additive Information A further benefit of this approach is that the narrowest possible drilling windows can also be evaluated and as a result, options for extending TD and potentially eliminating casing strings can be considered, leading to considerable savings, which are highly prized at all times, but especially so in a low oil price environment.

Sludge formed downhole in the production interval can be classified into crude oil-based or mud-based sludge. Sludge obstruction may result in partial or total loss of well productivity. Oil-based mud is commonly used in drilling of the pay zones in sandstone formations as a less/non damaging fluid. Oil-based mud typically contain emulsifier, viscosifer and other additives including polymer blend and calcium carbonate to serve different functions. Presence of emulsifier may increase emulsion tendency upon interaction with downhole environment. The resulting emulsion might be tight to an extent that a thick sludge is formed which can impair well productivity. Similarly, oil-based sludge may form from oil/water interaction in presence of emulsifiers, asphaltene, wax, solids, shear, etc. Identification of the sludge material will help in development of an effective chemical treatment to remove formation damage and restore well productivity. In this study, an extensive laboratory work was conducted to explore potential interactions of different downhole environment contaminants/factors on formation of oil-based and mud-based sludge. Typical mud-based and crude oil-based sludge samples were characterized using different analytical techniques including solvent extraction, XRD, TGA, ICP and viscosity. The results showed that the mud-based sludge sample contained calcium carbonate, dolomite quartz as the main components in the inorganic phase while the organic phase include polymers and oil. The oil-based sludge sample contained mainly water (82 wt%) with some solid particulates and asphaltene in the organic phase. Analysis of supernatants generated from solubility tests conducted for the mud-based and oil-based sludge samples revealed in addition to the high amount of calcium presence of iron in considerable amount (nearly 1,000 mg/L). Interaction of ferric chloride, quartz with an invert-emulsion mud was investigated. A significant increase in viscosity was observed upon incorporation of these contaminates with the mud sample. Iron ions in the aqueous phase tended to stabilized emulsion. This paper presents in detail mechanisms of mud-based and crude oil-based sludge formation upon interaction with environment. It also examined several chemical formulations for removal of mud-based and oil-based sludge samples.

With the development of new oil formations and with the advent of new directions in the global energy sector, new requirements for materials for well construction appear. With the close attention to environmental footprint and unique properties, one of the promising materials for well cementing is geopolymers. Being a relatively new material, they are characterized by low carbon footprint, high acid resistance and attractive mechanical properties. This article is aimed at developing new geopolymer slurries for the oil industry, their characterization and field implementation analysis. With the ultimate goal of developing a methodology for the analysis of raw materials and designing the geopolymer slurries, studies were carried out on various raw materials, including different types of fly ash. Based on the data obtained and rapid screening methods, an approach was developed to formulate a geopolymer composition recipe. Since not all cement additives directly work in geopolymers, special attention was paid to control the thickening time and fluid loss. The methods of XRD, XRF, ICP-MS, density, particle size distribution measurements as well as API methods of cement testing were used to understand the composition and structure of the materials obtained, their properties and design limitations. A special approach was applied to study the acid resistance of the materials obtained and to compare with conventional cements and slags. Using one of the most common sources of aluminosilicate, fly ash, formulations with a density of 13.5 – 16.5 lbm/galUS were tested. A sensitivity analysis showed that the type of activator and its composition play a critical role both in the mechanical properties of the final product and in the solidification time and rheological properties of the product. The use of several samples of fly ash, significantly different in composition, made it possible to formulate the basic rules for the design of geopolymers for the oil industry. An analysis was also carried out on 10 different agents for filtration and 7 moderators to find a working formulation for the temperature range up to 100°C. The samples were systematically examined for changes in composition, strength, and acid resistance was previously measured. Despite the emergence of examples of the use of geopolymers in the construction industry and examples of laboratory testing of geopolymers for the oil industry, to the best of our knowledge, there has been no evidence of pumping geopolymers into a well. Our work is an attempt to develop an adaptation of the construction industry knowledge to the unique high pressure, high temperature conditions of the oil and gas industry. The ambitions of this work go far beyond the laboratory tests and involve yard test experiments.

Depleted Fracture Gradients have been a challenge for the oil and gas industry during drilling and cementing operations for over 30 years. Yet, year after year, problems related to lost circulation, borehole instability (low mud weight due a low fracture gradient), and losses during cementing operations leading to NPT and remedial work continue to rank as some of the top NPT events that companies face. This paper will demonstrate how the geomechanical modeling, well execution and remedial strengthening operations should be implemented to provide for a successful outcome. The use of a Fracture Gradient (FG) framework will be discussed, and the use of a negotiated fracture gradient will highlight how the fracture gradient can be changed during operations. This paper will also show actual examples from Deepwater operations that have successfully executed a detailed borehole strengthening program. Through our offset studies and operational experience, we will provide a format for navigating complex depleted drilling issues and show an example on recovering from low fracture gradients. This paper will demonstrate (1) how our framework facilitated multi-disciplinary collaborative discussion among our subsurface and well engineering communities; (2) how the impacts of drilling fluids and operational procedures can change this lost circulation threshold; and (3) how our negotiated FG approach has successfully delivered wells drilled in narrow margins.

Many mature gas reservoirs in China have very low formation pressure, like Yakela, Dalaoba, Kekeya etc. The formation pressure coefficient ranges from 0.6 to 0.9. Conventional well killing fluids easily leak into the formation and damage the well productivity. There are alternative well killing fluids in the industry to kill low-pressure formations, including foamy fluid, oil-based emulsion fluid and well killing fluid with density reducing agent. However, the densities of these alternative well killing fluids are mostly higher than 0.8 g/cm 3 , and the cost is high if large volume of density reducing agent is used to decrease the density to lower than 0.8 g/cm 3 . In this paper, a formula of nitrogen foamy well killing fluid is developed and successfully used in sand removal operations in low-pressure gas reservoirs. A series of tests are conducted to select the optimal foaming agent, foam stabilizer and other additives. Sodium dodecyl sulfate is selected as the foaming agent. However, the properties of Sodium dodecyl sulfate are not stable in hard water, so we use dodecyl dimethyl betaine with sodium dodecyl sulfate together to increase the foaming ability in tough water environment like in the desert area. Xanthan gum is selected as a foam stabilizer because it can thicken the fluid phase and reduce the drainage speed. Gelatin is also added into the formula because it can form stable coacervate with xanthan gum. The concentration of each additive is also optimized through lots of tests. Then the properties of the foamy well killing fluid are tested. Its density is between 0.50-0.80 g/cm 3 and is adjustable. Under the temperature of 150°C, its plastic viscosity is 51mPa.s; its yield point is 51.5 Pa; the half-life period reaches 3055min. These basic properties meet the requirements of being used as well killing fluid. Salinity tolerance and oil resistance tests are also conducted to see the toughest environment that the fluid can be used in. The results show that the formula can be used in the oilfield where the water salinity is less than 100000 mg/L and the oil content is less than 15%. A model of calculating the equivalent density of the foam is developed. Scenarios of field application and onsite maintenance are also established. If a completion operation or a workover operation lasts for more than 24 hours, the foamy fluid needs to be maintained every day to guarantee its performance in the wellbore. The newly formulated well killing fluid has been used in three wells in Yakela condensate gas filed in Tarim Basin, western China, where the formation pressure coefficient is 0.67 and the formation is strongly water sensitive. A foamy well killing fluid density of 0.72g/cm 3 was used (surface density 0.53 g/cm 3 ) for the sand removal operation in well Ya2-2-4. No fluid loss has been observed during the whole operational process. Neither gas seepage nor oil overflow has been observed during well killing. The well has recovered from production after workover and the production rate reaches 90×10 3 m 3 natural gas with 12t condensate oil every day. The new formula of foamy well killing fluid not only shows good laboratory properties under 150°C, but also proves to be a good solution to the downhole operations in low-pressure and depleted reservoirs.

Successful Wellbore Clean Up (WBCU) operation is one of the key aspects in delivering a high productivity well. Conventionally, in this phase, a series of surfactant and solvent pill is circulated downhole to "clean" the well. Poor job execution at this stage usually will result to tremendous amount of time to clean out the well or worst leaving the well with a "dirty" brine. Eventually this will lead to impairment in the well productivity. The Operator experienced strings of non-performance in their WBCU operation. This is reflected by extensive circulation time and poor quality of the brine downhole. Coupled with pressing low crude oil price, the Upstream business of the Operator collaborated with their Downstream counterpart to co-create their own in house, low cost and high performance WBCU chemicals. Not only that the new chemicals resolved the operational issues faced by the Operator, it also created significant values within the company itself. The paper will discuss the process and implementation of the novel WBCU materials within the Operator's operation. The performance of a WBCU surfactant is measured by its effectiveness in cleaning various types of downhole residues as fast as possible. The design of the new WBCU surfactant hinges on these criteria. In the lab, the performance of the material is measured using a "cleaning efficiency" test at different drilling fluids densities and WBCU formulations. Series of iterations were performed to determine the best chemistry for the WBCU surfactant. Finally, a field trial was conducted in one of the Operator's well, Well T-2 to gauge the product's performance in the real environment. The field trial in well T-2 was successful in achieving a cleaner brine at a rate faster than well T-1, a similar well of the same campaign. Well T-1 used a conventional surfactant and solvent product in the current market. The WBCU used in well T-2 managed to reduce the final NTU of the brine up to 45 % as compared to final NTU observed in well T-1. A reduction in the operation hours up to 4 hours was also seen in well T-2. This has contributed to cost savings in rig time up to USD 75K. The successful performance delivery of the Operator's in-house products has showcased a fruitful collaboration between different workstreams within the Operator. Deep understanding in the chemistry of solvent and surfactant from the Downstream business helps to solve the pain points by the Upstream business. Insights on product performance and applications are transpired within the team to innovate a solution with better performance at lower cost. This has paves way for more opportunities in product development especially in specialty chemicals.

Owing to superior temperature stability in comparison with water-based drilling fluids, oil or synthetic-based drilling fluids are generally preferred for high temperature and high pressure (HTHP) formations. However, the thermal degradation of emulsifiers and polymeric components under HTHP conditions that results in loss of rheological and filtration control, barite sag or even fluid phase separation also occurs. It is a challenge to sustain these properties stable under such harsh condition. Since nanoparticles have potential to provide better thermal stability, improved filtration loss as well as emulsion stability, the aim of this study is to investigate the effect of nano carbon spheres on the properties of oil-based drilling fluids under high temperature conditions. The nano carbon spheres were synthesized with the hydrothermal reaction of glucose. The influence of nano carbon spheres on the rheological, filtration, emulsion stability, settlement stability, as well as lubricity of a typical mineral oil-based drilling fluid with oil to water ratio of 80:20 was investigated before and after thermal aging at 180 and 200°C, respectively. The structure characterization showed that the uniform hard nano carbon spheres exhibited intermediate wettability. Laboratory performance test indicated that, for the oil-based drilling fluid, the addition of nano carbon spheres improved the rheological properties in terms of yield point and the ratio of yield point to plastic viscosity, which is beneficial for transporting of drilling cuttings. After thermal aging at 200 °C, the filtration loss volume was reduced as high as 70%, and desirable filter cake quality was obtained by incorporation of 1.0 wt% spheres, meanwhile the electrical stability was improved both before and after thermal aging. Furthermore, the fluid formulated with the nano carbon spheres generated better barite sag control. The polarizing microscope observation showed that the nano carbon spheres accumulated at the water-oil interface and formed a steric barrier which probably explained the reason of the above enhanced performance. The green synthetic routes and environmental friendly characteristics of the nano carbon spheres, in combination with the excellent properties suggested that the nano carbon spheres hold potential as multi-functional additives for formulating oil-based drilling fluids for HTHP drilling operations.

Drilling though salt is not a new challenge in the petroleum industry, with successful exploration and appraisal wells in salt environments paving the way for complex field developments. A detailed summary of how these advancements have subsequently evolved into the technology and methods being used today is presented. The numerous challenges, and the resulting solutions, of drilling in salt environments are well documented; a comprehensive review of the relevant published industry literature has been conducted. Additionally, workshops with several major service vendors have been held to ascertain the current status of research and new product development. These two areas form the foundation of this work and have been weaved together and presented to establish what is the state of the art in salt drilling. Since the first salt wells were drilled, the drilling industry has changed considerably. Significant advancements in salt drilling technologies and methods have been made in areas such as: best drilling practices, salt formation geomechanics, salt formation geochemistry, drilling fluids, well cementing, directional drilling, drill string and drill bit design. These advancements have all been clearly delineated in a chronology of continuous improvement, compounded by the considerable weight of industry experience and lessons learned which has in turn led to optimisation, and increased efficiency, of salt drilling operations. Today, salt drilling is prevalent in areas such as the Gulf of Mexico, deep-water offshore Brazil, and deep-water West Africa, where the boundaries are continually pushed due to the perseverance of both petroleum operating companies and service vendors. The existing body of literature on salt wells is large and covers many disciplines of the upstream business, from wildcat exploration through to production. However, this focus is solely on drilling, combining and summarising many years’ worth of experience, learning, research, and development, to present what is the state of the art in salt drilling.

Oil-based mud (OBM) is the first choice for complex deep wells due to its advantages of high-temperature resistance, good lubrication and borehole stability. But barite sagging under ultra-high temperature during the long-time stationary completion operation may lead to serious problems in ultra-deep wells, for instance, pipe sticking, density variation and well control problems. In this paper, the influence of high-temperature and high-pressure (HTHP) on the performance of oil-based completion fluid was studied, and a model of rheological parameters was established with HTHP static sag law. The barite sagging stability was evaluated by a high temperature (220°C) and high pressure (100MPa) sag instrument. The results indicated that RM6 value and static shearing force were the main factors of affecting the settlement stability. The viscosity of the completion fluid significantly decreased with the increase of temperature, but increased with the increase of pressure. In addition, the relationship was also studied between HTHP rheology and atmospheric pressure rheology at 50°C. The results showed that when RM6 value was kept above 10, the sag stability factor (SF) of oil-based completion fluid was less than 0.52 at 190°C for 10 days, which proved a good high-temperature sag stability. Furthermore, the anti-high temperature property of oil-based completion fluid was improved through enhancing the temperature-resistance of the additives. And the high-temperature-resistant organic soil was introduced to raise the RM6 value and the static shearing force. Based on these solutions, the barite sag under high temperature of the oil-based completion fluid was prevented during drilling and completion operation in ultra-high temperature wells. The oil-based completion fluid was successfully used in Well Keshen 17 (175°C,7475 m) in Kuche piedmont structure and TT 1 well (210°C,6500 m) in Sichuan basin. The casing run smoothly, the oil-test operation was completed smoothly for 15 days, and no barite sag happened. It testified that the oil-based completion fluid had excellent of high-temperature sag stability. Therefore, this oil-based completion fluid is expected to be used widely in ultra-deep wells.

In this study, the highly sensing chemo-thermo-piezoresistive smart cement behavior as a function of temperature and pressure with a water-to-cement ratio of 0.38 was investigated. Series of quality control, curing, compression and high-pressure high-temperature (HPHT) lab experiments were performed to evaluate the smart cement behavior with pressure and temperature variations. Vipulanandan p-q curing model was used to predict the changes in resistivity with curing time. The piezoresistivity strain of smart cement after 1 day of curing under 140 °F was 207% which is much higher than the regular cement failure strain of 0.2%. The Vipulanandan p-q piezoresistivity model also predicted the experimental results successfully. Observed fluid loss and gas leak after 30 minutes of testing was recorded. The measured fluid loss was predicted using the Vipulanandan fluid loss model and compared to the API static fluid loss model. Smart cement detected and sensed gas leak throughout the fluid loss test. During the gas leak through the piezoresistive smart cement slurry, the resistivity change was positive which could be used as an indicator for immediate gas migration. During the gas leak in the smart cement slurry, the resistivity increase was about 36% at pressure gradient of 1,800 psi/ft for 70 °F curing. Vipulanandan fluid flow model, generalized Darcy's Law, predicted the non-linear responses of gas leak velocity (discharge per unit area) to the applied pressure gradient. Additionally, the electrical resistivity changes predicted the gas leak velocity in the smart cement at different curing temperatures.

The surge in the worldwide demand for hydrocarbons has resulted in considerable interest in drilling for unconventional resources. The Drilling Engineering Team has reduced the duration and cost of drilling wells by 80% in drilling days and 73% in well delivery cost while targeting more precise sand-channel targets in the Unconventional Field presented in the paper, during a time period of about 10 years. Optimizing the casing design (moving from seven casing strings to four casing strings), drilling practices (maximizing drilling parameters), and completion practices (moving towards 4-½-in cemented longstring instead of lower/upper completion), resulted in reducing the number of days and the associated drilling cost. The improvements include: Modifying hole sizes (slimming wells starting from 34-in section to 22-in section). Combining sections that were previously isolated (for example, combining the targeted sand-channel reservoir with a long shale interval above it in one section). Eliminating drilling liners and completion tiebacks (moving towards 4-½-in cemented longstring instead). Improving the drilling fluids program (moving towards high salinity NaCl polymer drilling fluid system for the shallower sections, and reducing mud weights needed to stabilize the long shale interval from 100+ pcf toward 70-80 pcf by utilizing OBM), Increasing top-hole rate of penetration by strategically moving all the directional nudging into the 8-½-in/8-⅜-in OBM drilled hole section, and decreasing cost of top hole bottomhole assemblies. Introducing new technology 8-½-in/8-⅜-in PDC bits that drilled the entire hole section with one bit. Introducing an updated combined logging program.

Recently, shale gas resource has been developed beneficially on a large scale in China. More than 400 shale gas horizontal wells have been drilled in south Sichuan since 2014. However, with the increasing buried depth of target stratum and the extension of horizontal intervals of shale-gas horizontal wells, the development of Chinese shale gas is becoming more and more difficult. Over the past four years, some wellbore instability related issues–stuck pipe and rotary steering system fish downhole occured during drilling the shale gas wells. The reason is particularly analyzed based on the drilling performance data of these horizontal wells, which will offer the establishment of general practice guidelines and recognition of opportunities for improvement in south Sichuan shale drilling. Oil-based drilling fluid (OBM) is a typical drilling fluid type currently used in the south Sichuan shale play. However, water-based mud (WBM) has also been used in more than 60 wells since 2015. It is analyzed the drilling performances of over four hundred horizontal south Sichuan shale wells drilled by 14 operators from 2014 to 2018, including overall drilling days, well depth, lateral length, as well as fish rotary steering systems. A comparative analysis is also made among different drilling fluid types of different operators to assess their performances and to identify the key challenges when drilling south Sichuan shale. The analyses contained formation characteristics, mud chemistry, mud rheological property, plugging property, solid content, stability, density and chloride and so on. Then, lots of experiments are carried out to solve the problems of borehole stability and hole cleaning. The analysis shows that the drilled well depth and the horizontal length are getting bigger and bigger. The overall performance of WBMs lags behind that of OBMs in south Sichuan shale drilling. Most fish RSS happened when the operations of back reaming, pick up stands and trip-out were carried out. The lost circulation nearly covered all the well sections. These issues lead to excessive amounts of time spent on costly fishing, sidetracking, plugging operations and the long drilling days. The performances of oil-based drilling fluids of different operating companies were quite different. Lab test results show that shale formation is more complex than before. With the increase of well depth, the clay minerals decreased and brittle minerals raised. The natural fractured formation increases and the drillable "sweet" layer thins. The main mechanics of shale instable is the strong capillarity on amphiphilic shale surface causes the invasion of fluid into formation, then leads the fracturing and de-lamination along the bedding planes and enlargement of natural fractures. It is effective to control the harmful low-density solid for improving the performance of OBM. The suitableφ6 value of OBM and a big delivery capacity will work in hole cleaning while drilling lateral sections. A nanoscale polymer was developed in lab to improve the plugging effect significantly after adding in OBM. An amphiphobic material was used to transform the wettability of shale, which was favorable for borehole stability. The analyses and results of this study on drilling performance data provide lessons learned and general guidelines for current drilling practices such as drilling fluid selections and mud property control in the south Sichuan shale gas of China.

The oil and gas industry uses chemicals like acids and oxidizers as polymer breakers in hydraulic fracturing and triazene and glyoxal for H 2 S mitigation. In addition to serving the intended purpose, the chemicals cause secondary effects like non-specific oxidation, acid corrosion, precipitation and danger to oil field personal. We present novel, environmentally preferable chemistries to address various issues in the oil and gas industry. The studies using -Mannanase HT enzyme as polymer breaker showed breaking of cross-linked guar polymers at elevated pH (7-12) and temperature ( 175°F) ranges. Chlorophyll-treated cross-linked fluids showed more than 90% viscosity reduction. The chlorophyll worked efficiently up to 250°F, but the optimum temperatures are at 175 to 200°F. The chlorophyll treatment also showed a reduction of molecular weights of a linear polymer from 1,472,000 to 6,000. Further, H 2 S mitigation was addressed using a novel recombinant Sulfide Quinone Reductase enzyme (SQR). Functional studies conducted by treatment of soured brine and oil revealed 72% and 90% reduction in H 2 S concentration, respectively. The scavenger showed 75% reduction of sulfide in simulated mixed production samples containing a 30:70 ratio of brine to oil. Field testing of SQR showed a reduction of headspace sulfide from 400 ppm to 2 ppm and BS&W values less than 0.5%. These studies confirm that this novel biotechnology based environmentally preferable tools can be successfully used to break polymers and mitigate H 2 S in various systems. Further, the biotechnology solutions have several advantages such as meeting environmental regulations, reducing, or eliminating secondary effects and health hazards that are associated with current chemical treatments.

Filter cake formed by barite-based drilling fluid is often soaked with chelating agent removal treatment 24 hours to be dissolved after the drilling operation. During the removal process, the chelating agent absorbs barite from the filter cake to form a barite chelate. Due to the heterogeneity of the filter cake thickness where the thinner parts may dissolve faster and due to long soaking time, the removal fluid will have more time to invade the formation. This paper investigates the interaction between the barite chelate and the calcite formation after filter cake dissolution. The barite filter cake was formed over the face of calcite rock samples using a High-Pressure High Temperature (HPHT) fluid loss apparatus. Chelating agent solution was then used to dissolve the filter cake. NMR spectroscopy and X-ray CT images were applied to study the changes in the pore size distributions of the calcite rock samples at pre and post-invasion states. The result of this work showed that barite chelate released barite precipitates into the pores of the cores and then absorbed Calcium cations from the rock minerals. The barite chelates released barites into the macropores and absorbed cations from the micropores. CT scan and spatial NMR analysis also showed that the chelating agent was not able to create wormholes after releasing barite. A detailed explanation of the observed results is presented with supporting results. Based on the obtained results in this work, several recommendations were drawn for removing the barite filter cake in the filed application without causing any severe secondary formation damage.