In a corrosive downhole environment, the service life of a completion can beseverely reduced if suitable precautions are not taken. Pipe made of corrosionresistant alloys (C.R.A.) is used to minimize corrosion. Recently, steelmanufactures have developed modified corrosion resistant alloys (C.R.A.),specifically derivatives of Cr13, that are characterized by a black smoothscale surface on the outside of the pipe.
When these so called "Super" or "Hyper" alloys were first used, occasionalslipping was reported by field personnel. Fortunately no string was lost and noinjuries occurred, however, precious rig time was lost in resuming safeoperations. These slippages occurred with various inserts and with all types ofslip-type elevators or spiders.
An investigation carried out by the University of Hannover revealed that thesurface scale on the pipe had a hardness of over 60 Rc. Even insertsspecifically designed for C.R.A. pipe that use special gripping elements, suchas the Micro-Grip™ system have a hardness that is only slightly higher thanthis surface scale. Using conventional wedge type spider and elevator systemscan lead to slippage under certain load conditions, if no special precautionsare taken.
Based on these results and on the operating principles of wedge type spidersand elevators, a new Compact Spider/Elevator was designed. This device can beeither air or hydraulically operated and puts an additional downward force ontothe slip, as much as 40 tons for the hydraulic version, so that a firm grip isassured. In addition to conventional steel inserts, the device can be equippedwith so called Micro-Grip™ inserts, a gripping system that distributes therequired load equally onto a large number of small peaks. This minimizes theindentation of each single peak and thus, as previous research and fieldexperience has shown, preserves the surface integrity of the pipe with regardto corrosion [2, 3, 4]. The device can be run flush-mounted, further enhancingsafety on the rig-floor.
In a corrosive downhole environment, the service life of a completion can beseverely reduced if adequate precautions are not taken. This is especially trueof tubular material made of corrosion resistant alloys (C.R.A.), which is oftenused to minimize corrosion. Due to the great variety of downhole conditionswithin a production well such as temperature, dissolved and undissolved gasesand their depth-dependent partial pressures, an optimal corrosion protectionsystem requires comprehensive planning. Analysis of the downhole conditionsleads to the selection of the appropriate material to assure the best lifetimeunder the corrosive environment present.
The pipe manufacturers have reacted to the special requirements of theoperating companies. The main component used to improve the corrosionresistance of an alloy is the addition of chromium. C.R.A. alloys with up to 13% percent chrome content are commonly used and occasionally the content ofchrome is higher to cope with special corrosion conditions.
Conventional spider and elevator inserts cause die marks that can promotecorrosion. A gripping system named Micro-Grip distributes the required loadequally onto a large number of small peaks, minimizing the indentation of eachsingle peak.
Well control has always been a very important issue in the oil and gasexploitation business, since it involves money savings, people safety andenvironment threatening. The advancement of the exploration frontiers fromonshore to offshore fields, particularly, deep and ultra-deep waters, hasincreased even more the relevance of kick control and blowout prevention duringdrilling operations. Widely used drilling practices have been optimized andre-evaluated, so have new technologies been developed to handle specific issuesrelated to deepwater drilling operations, such as reliable and efficient wellcontrol practices. This effort has great importance to some countries likeBrazil, which have most part of their oil and gas production (close to 75%)concentrated on offshore wells, about 70% of those reserves are located in deepwaters. Regarding such scenario, this article presents a comprehensive anddiscussed literature review about well control in deep and ultra-deep waters,covering the evolution of the analytical and numerical kick models. Amathematical model has been developed to predict the pressure behavior insidethe annulus during a gas-kick circulation out of the well in deep waterscenarios. Considerations regarding the effects of wellbore geometry,frictional pressure losses, influx expansion, and two-phase flow models havebeen implemented in the present model. The analysis of the effect of someimportant parameters in well control in the surface pressure, such as the pitgain, water depth, mud density and pump flow rate are presented.
The exploitation in deepwater and the development of concepts related tothis activity has been changing a lot throughout the years. In the sixties, forexample, the exploitation and the development of offshore fields used to berestricted to 150 ft water depth. Nowadays, depths up to 1,300 ft areconsidered as deep water and above 3,300 ft are considered as ultra-deepwater.1
Particularly in Brazil, about 75% from the national production come from theCampos basin, in the north coast of Rio de Janeiro, with more than 70% of thosereserves located in deep and ultra-deep waters. 2 Deep waterdrilling in Brazil was stimulated by the discovery of the Albacora field, in1984, in a water depth that varies from 1,000 to 6,500 ft. In 1985, Marlimfield was discovered with the well RJS-219, in 2,750 ft water depth. In 1994,the Marlin-4 well (3,400 ft water depth) was completed and its production wasstarted. In 1996, the giant field of Roncador was discovered, with water depthsvarying between 5000 and 10,000 ft. The brazilian record of water depth is the1-RJS-543 well, located at Roncador field, reached in November 1999 in a9,300ft water depth.
In deep water drilling operations, an accurate control of all the drillingparameters, added to a detailed project and program are factors of extremeimportance in the environmental, economic and security aspects. A permanentconcern in these operations is the control of kicks and the prevention ofblowouts.
The first mathematical model of kick circulation was proposed in1968.3 The model disregarded the friction pressure losses in theannulus, the slippage speed between the gas and the mud, with a uniform annuluscapacity and the gas insolvable in the mud.
The model of Ref. 4 incorporated the effect of friction pressure losses inthe flow inside the annulus. Even though there was an improvement regarding theprevious model, it presented results that did not match field data,properly.
In directional drilling, MWD technology is applied to transmit directional and petrophysical data from downhole. In combination with modern directional drilling tools such as rotary steerable systems, MWD technology has enabled the drilling of complex 3D well profiles precisely placed in the reservoir. However, even on these high-tech wells the drilling process itself is still controlled mainly using traditional surface acquired data such as hook load, ROP, RPM etc.
The transmission and utilization of downhole drilling process data in addition to the surface logging data offer a not yet fully explored potential for drilling process optimization, since modern data acquisition technology close to the bit can provide not only more accurate data but also important additional parameters not available at the surface. Examples of value-adding downhole drilling process data are annulus pressure, weight-on-bit, drillstring bending, RPM, bit torque and dynamics diagnostics. Additional drilling process information on drilling hydraulics or drillstring friction can be obtained by feeding drilling engineering algorithms with downhole and surface acquired data.
The paper provides an overview of the available downhole drilling process data and demonstrates with numerous case studies the value that these parameters add. Furthermore, the paper discusses factors constraining the use of the technology and gives an outlook on future developments in drilling process optimization utilizing real-time downhole data.
Drilling optimization remains a key issue in the drilling industry due to the high drilling costs in today's challenging applications such as Extended Reach Drilling (ERD), designer profile wells, deepwater wells, drilling in depleted reservoirs etc.
Over the past years, the drilling rig industry has made significant progress in introducing computer-based instrumentation, power-handling tools and automated equipment on the rigs to improve rigsite safety and to optimize the drilling process. The introduction of Local area networks (LAN) on the rig has improved the acquisition of data from surface sensors and information sharing on the rig.
In parallel, downhole MWD technology has made progress in miniaturization of electronics, quality, range, and reliability of sensors, and the development of specific diagnostic techniques to describe the downhole environment. These sensors provide new sources of downhole information for the driller, previously trained on controlling the drilling process using only his rig dials.
The purpose of this paper is to demonstrate how real-time downhole drilling process data, along with surface acquired data, can support the decision making progress on the rig to optimize the drilling process.
Downhole Drilling Process Measurements and Applications
The following provides a comprehensive overview of the drilling process measurements available in today's downhole Measurement-While-Drilling (MWD) systems. Case studies describe how the data are utilized at surface to overcome drilling related problems.
Although knowledge is predicted to surpass oil and gas reserves as the most important asset in 21st century oil and service companies, engineers remain cynical about the benefits of current knowledge management initiatives. This paper discusses problems such as the strong bias of existing knowledge management systems in favour of document searching and focuses on how overlooked areas can be addressed. Results of a collaborative project with 5 major oil companies aimed at overcoming some important limitations of current knowledge systems are discussed. A key feature of the initiative is software to integrate knowledge capture and reuse into normal work processes. The software uses well data and stored drilling experiences, including problems and solutions, from a global drilling and completions database provided by the member oil companies. Experiences with deployment of this software into oil companies will be covered as well as the results of research projects on automated learning and case based reasoning to enhance the company knowledge base for optimal design of new wells. The study of overall well quality has also been included in the project. By defining well quality metrics and then examining them collectively, we can better assess drilling performance in a given field, and ascertain if the company is using its knowledge to improve new well production and cut costs.
This report considers two main categories of knowledge exchange, viz. people to people networks and IT assisted people to knowledge base exchange. Companies do not take a uniform approach to managing knowledge. In some companies the strategy centres on the computer. Knowledge is carefully codified and stored in databases where it can be used easily by anyone in the company. Hansen1 calls this the codification strategy. Other companies rely mostly on direct people to people contacts.
Examples studied in the oil and gas industry indicate that both strategies are necessary for a successful knowledge management process. A review of existing knowledge management systems is presented with an emphasis on systems deployed into the oil and gas industry. Several workshops were organized by CSIRO with oil industry participants to elicit their current most pressing needs in the knowledge management area. These workshops and other recent industry studies highlight missing elements needed for the acceptance of knowledge management initiatives into the oil industry.
Software to fill gaps in existing knowledge base systems has been produced, the major contribution is integration of knowledge from diverse data, document and knowledge stores into everyday planning and operational processes. Another useful contribution is automation of knowledge extraction from text documents. The new software is described and results of trials with oil companies in Australia, Europe, the Middle East and North and South America are discussed. The paper also describes current work on overall quality metrics to enhance the knowledge store. The authors believe that the study of overall well quality is a neglected area of the industry, for example, well quality aspects such as formation damage, drilling interactions, and hole rugosity tend to be treated separately in the literature.
OMV has been drilling for oil and gas in a roughly 5000-km 2-area northeast of Vienna for more than fifty years. Since 1999, previously applied conventional type service contracts were gradually changed to performance-based incentive type contracts, which increased drilling performance up to 50% over a three-year period. The impact of generating "ownership" within the service company's and contractor's staff is reflected by both the increased quality of the wells drilled and the enhanced safety record of the rig(s). The paper describes the incentive scenarios developed for a mature operating are, the pitfalls and obstacles that had to be overcome in implementing new contractual concepts in a traditional operating environment and the increases in operating efficiency gained from the new culture.
The concept of including service companies and contractors into the overall project risk and awarding exceptional performance with additional bonus payments is by no means new. In one of the first papers on the subject, Cahuzac1 stated that "in most cases, standard dayrate remuneration is not the best way [...] due to the differences which exist between the operator's goals and the contractor's incentive to maximize revenue and cash flow". In the contract scenario advocated by the author ("Incentive Dayrate Contract"), the traditional operator/contractor responsibilities remained intact, with the contractor being more closely involved on an advisory basis to enhance performance and allow completion of a well ahead of a previously agreed total well time, which normally would reflect historical average performance. Thus, a shorter well time partially offsets revenue losses due to fewer accountable rig days with potential incentive bonus payments. Over a 40 well and 3-year period of onshore France operations, the author reported average improvements of 35%, with safety records set along the line. In another paper, Oeffner2 presented the concept of "Shared Risk" contracts, where a total well time is negotiated between operator and contractor, and responsibility for potentially influencing risks are allocated to one or both of the parties ahead of spud. The author already introduced a scenario, where time overruns up to e certain upper limit (e.g. 15%) are reflected in zero dayrate for the contractor, while finishing the project ahead of time resulted in 50% of the saved dayrate still paid to the contractor as an incentive bonus.
Geehan, et.al.,3 introduced the concept of integrating the solids control and drilling fluid engineering part into the on-site drilling and operations engineering group, and assessing their performance based on key indicators such as
Efficiency of Solids Control Equipment
While the authors not yet advocated an incentivized scenario for drilling fluid services, simply addressing the issue of qualifying/quantifying solids control efficiency and drilling fluid services resulted in a reported reduction of chemical/product cost of 32%.
Marshall4 addressed the problem of defining incentivized or even turnkey contract scenarios for remote (or better : little known) areas. His paper reflects the downturn prevailing in the drilling market at the end of the 1980s, thus "benefits for the contractor [from accepting an incentivized contract] are the opportunity to gain a contract for a rig that would otherwise be lost [...]". The author concluded that "Incentive drilling contracts, including footage and turnkey, are becoming increasingly common. However, the majority of such contracts are limited to the U.S. where most contractors are based and where risk is minimum".
Effective blowout preventer (BOP) requirements and well control policies are crucial in maintaining safe drilling and workover operations. These requirements/policies generally are tailored to the individual oil and gas operator's specific drilling environment. Changes in well profile, depth, temperature, pressure, hydrogen sulfide concentration, and safety margin may require changes in BOP equipment and well control. Saudi Aramco has recently revised their equipment requirements and well control policies in an effort to further optimize drilling safety and efficiency in the Kingdom of Saudi Arabia.
This paper discusses changes in BOP stack arrangements, kill/ choke line requirements, replacement part criteria, elastomer application limits, and use of variable bore rams and shear blind rams. Also included are requirements for number of isolation barriers, pressure testing/maintenance, and minimum overbalance. A new tripping policy and shut-in procedure are also discussed, with the introduction of a new trip sheet and kill sheets. Specific well control policies are provided.
Background and Introduction
In 1994, Saudi Aramco resumed the Khuff gas development and Pre-Khuff exploration programs, which had been discontinued in the late 1980s. The associated activity level increased from one deep drilling rig in 1994 to twenty-two deep gas rigs at present.
These gas wells range in total depth from 14,000' to 19,600' with bottom-hole temperatures of 300 to 350 degrees F. Bottom-hole pressures in some formations require as high as 162 pcf mud weight, while 90 to 100 pcf is typically needed to control the gas reservoirs. Shut-in wellhead pressure is approximately 6,000 psi. Hydrogen sulfide (H2S) concentrations in Khuff wells can reach 20% in some areas.
The first Khuff gas horizontal well was drilled and completed in 1997. Thereafter, both horizontal and vertical wells have comprised the deep gas program.
In 1998, two well control incidents occurred and prompted an in-depth operational review. As a result of this study and the continued emphasis on drilling deep gas, BOP and well control policies were revised. Additional revisions were also made as part of an ongoing optimization effort.
All standard BOP stacks were reviewed to ensure the equipment complied with accepted industry practices and provided proper well control safety for all drilling/workover applications. Major stack design considerations were evaluated. Among these were pressure rating, component selection and arrangement.
1) Pressure Rating
Pressure ratings of the standard BOP stacks are 10,000 psi (high pressure), 5000 psi (medium pressure), and 3000 psi (low pressure) as shown in Figures 1 through 5. Selection of the proper stack is determined by the ‘worst case' pressure containment, which occurs when all the drilling fluid has been evacuated from the annulus and only low-density formation fluid remains.
Working pressure rating of the BOP and burst rating of the casing strings (with a 1.33 minimum design factor) were re-verified for all pressure applications to ensure a shut-in capacity greater than the worst pressure condition that could be imposed during a well control incident. No changes were required in the BOP pressure ratings or pressure applications.
2) Component Selection
Main components of the standard BOP stacks include the annular preventer, fixed pipe rams, variable bore rams (VBR), blind rams, shear blind rams (SBR) and drilling spool. Components are selected by the maximum anticipated surface pressure, wellhead temperature, and H2S concentration.
Hardbanding materials are used to protect tool joint drillpipe against wearin drilling operations. Hardbanding shall resist wear in openhole conditionswith a minimum damage to upper casing. Laying down drillpipe for hardbandingrepair can significantly increase rig time and tubular costs. All hardbandingproducts applied for Sincor were wearing out completely after drilling 15,000ft in 50 hours in the reservoir. It was necessary to search for new hardbandingalternatives with an extended lifetime. A field evaluation program was designedto compare wear resistance of different commercial hardbanding materials and toevaluate new techniques for welding tungsten carbide pellets with alloyingwires and for testing of tungsten carbide spheres being laser applied.Hardbanding products were selected upon analysis of wear mechanisms occurringin drillpipe while drilling horizontal wells in Sincor. Wear resistance wasmonitored in terms of cumulative drilled footage until gauging complete wear ofhardbanding on tooljoints. One of the newly developed hardbanding products wasfinally selected as the best option after considering its superior wearresistance, minimum expected casing damage, and moderate cost. This is thefirst reported successful application of tungsten carbide pellets welded withina hard matrix provided by an alloy wire for hardbanding purposes.
Wear of drillpipe is an important issue for drilling operations in Sincorarea. Wear increases operational cost due to repair of components, rig time tochange out worn down components, and lost of valuable tools. Wear of componentshas been reported in the tool joint drillpipes since start of operations.Hardbanding and repair cost for a 5,000-ft string can reach up to US$ 150,000over the string lifetime. With this amount of money and time invested in wearcontrol, high consideration was given to develop material specifications forrequesting wear resistant materials. Other solutions implemented in Sincor toreduce drillstring wear are the following:
Use of down-hole tools, i.e. Hydroclean drillpipe, for better hole cleaningand a consequently reduction of the backreaming while drilling horizontalsections.
Optimization of drilling practices such as mud circulation, use of Hi-Vispills, and backreaming parameters.
Use of mud additives, i.e. Ecolane solvent, and heating the mud to reducedrillstring friction.
Use of several types of hardbanding materials.
This work is aimed to find the most appropriated hardbanding material forprotecting drillpipes in openhole conditions. Minimum casing wear andenvironmental pollution due to chromium discharge within the drilling fluidswere identified as special concerns.
Sincor is an operating oil company created in 1997 and it is comprised byTotal Venezuela S.A., PDVSA Sincor S.A., and Statoil Sincor A.S. The companystarted operations in 1998 to exploit the Zuata reservoir located in theOrinoco Belt in Southeastern Venezuela. Reservoir is characterized by an 8-°APIheavy crude oil in unconsolidated sand with extensive shale bedding. Wells aredrilled in clusters to minimize environmental impact. Each cluster has anaverage of 12 extended reach wells having an average horizontal section of4,450-ft in length. Frequent backreaming is required for hole cleaningpurposes. This combination of unconsolidated sand and repeated backreaming asdepicted in Figure 1, are the primary causes for wear of drillstringcomponents. Drillpipe is laid down when tooljoint outside diameter is lowerthan 6-3/8".
Cuttings transport in underablanced drilling is critical especially while drilling highly inclined or horizontal sections. However, existing guidelines for cuttings transport in directional wells drilled underbalanced might be seldom established based on reliable experimental data because a few experimental studies1,2 has been conducted so far. In addition, most studies on cuttings transport or hole cleaning in underbalanced drilling found in literatures3-5 are covering only vertical wells. Even in drilling with conventional mud, it is reported6 that the prediction of critical flow rate (CFR) for cuttings transport in a ERW was inconsistency between the prediction models, though many studies have been done both experimentally7-11 and theoretically12-16.
We made a comprehensive experimental study on cuttings transport in aerated mud drilling using a field scale flow loop apparatus. We have carried out 63 experimental runs to measure the cuttings concentration covering over 300 flow conditions with annular test section inclination angles from 30 to 90°. From the experimental results, the performance or efficiency of cuttings transport in inclined annulus is evaluated based on the quantitative data of cuttings concentration in the annulus. The critical fluid flow rate for cuttings transport is also discussed.
Experimental Apparatus. Fig. 1 is a schematic drawing of the Cuttings Transport Flow Loop System (CTFLS). The 9-m long test section simulating a borehole annulus consists of a 5-in. (127.0 mm) ID transparent acrylic outer pipe (borehole or casing) and a 2.063-in. (52.4 mm) or 2.875-in. (73.0 mm) OD steel inner pipe (drillpipe). To make a visual observation and image analysis through the transparent section, CCD cameras and video recording system are equipped. The test section mounted on a movable frame can set its inclination angle from 0 to 90° in 15° increments. The test section can also simulate an eccentric annulus with drillpipe eccentricity of +0.8.
Knowledge capture, distillation, preservation, and sharing among project teams are challenging issues across widely distributed organizations. The teams need to share information, learn about and apply best practices and lessons learnt, in a structured, easily accessible manner: anytime and anywhere. The implementation of a project management system integrating worldwide, web-accessible organizational-learned knowledge hub is presented in this paper.
A Project Knowledge Portal (PKP) was implemented; containing links to corporate web based knowledge hub, including a structured repository for all project critical information. The Integrated Project Management system (IPMS) was developed as a process matrix, based on a company wide implemented standard. The PKP uses the IPMS to create an ISO 9001 compliant structure behind all applied project processes.
Organizational knowledge is generated, captured, distributed and preserved throughout every stage of the project. The team uses the PKP to create a one-stop-shop for project knowledge. The project specific management system is stored in the Project Hub together with all associated documentation such as standards, procedures, manuals, roles and responsibilities, audit and review systems, records, etc. All project members have access to the management system anytime. The records of the system are generated by team members and posted into the Project Hub. The required changes to the system are made via the Project Hub to the project member that maintains project specific management system.
Knowledge Management (KM) components of the web based PKP include real-time synchronous and a-synchronous E-collaboration tools to capture decision processes and have an audit-able trail for document control. The Portal includes a static filing repository in the form of the Schlumberger Knowledge Hub. QHSE Data, Lessons Learned and Best Practices are captured and made available for the rest of the organization. An example of implementation is presented in an actual project, with details of the roles and responsibilities and the impact on organizational learning.
Managing complex reservoir projects involves many challenges and issues. Integrated Reservoir Management and Optimization (IRO) and their components have been discussed in a number of references.1,2 In order to successfully and effectively manage IRO projects, to reduce costs and to introduce new technology appropriately, these projects should not only involve the asset team, but a number of experts widely distributed geographically. The asset team should also be able to capture the relevant knowledge and best practices that are also stored geographically. This brings the challenges for "Time Management" - real time interaction and synchronization, "Process Management" - synchronization of multi discipline teams with defined processes, and "Knowledge Management" - effective management of knowledge (knowledge capture, usage, mining, transfer). Knowledge management and transfer is also becoming a main issue with the current age and experience distribution in the Oil&Gas industry.
There are currently four basic collaboration scenarios: conferencing (personal, video), paper, email and web based. Increased complexity of the tasks, the organization and the disciplines, combined along with information overflow makes these collaboration tools ineffective. The project knowledge portal (PKP) that incorporates an Integrated Project management system and the collaboration framework, which is explained in this paper, is introduced as a solution for this challenge.
Tan, Chee P. (CSIRO Petroleum ) | Amanullah, Mohammed (CSIRO Petroleum ) | Mody, Fersheed K. (Shell International Exploration and Production, Inc.) | Tare, Uday A. (Baroid Product Service Line, Halliburton)
A major collaborative effort was undertaken to develop novel environmentally acceptable water-based drilling fluids with high membrane efficiency to help meet the future requirements of the petroleum industry. This paper describes the development of the drilling fluids and practical guidelines for maintaining shale stability with the drilling fluids. Specialised test equipment, including a membrane efficiency screening equipment, and test procedures were developed for simulation of key drilling fluid-shale interaction mechanisms. More than 300 membrane efficiency screening tests were performed on Pierre II shale samples to screen a wide range of novel compounds for their membrane generation capacity in the shale. Typical examples of the tests conducted with three novel compounds that generated moderately and highly efficient membranes are presented and discussed. The results demonstrate that some of the compounds are capable of generating membrane efficiencies of between 55% and 85%. The new generation of water-based drilling fluids developed performs essentially like oil-based muds in terms of shale stabilisation. Practical mud design guidelines developed can be used to optimise the drilling fluid design, in terms of mud weight, salt type and salt concentration, to manage time-dependent wellbore instability in troublesome shale formations efficiently.
Argillaceous formations account for about 75%; of drilled sections in oil and gas wells and cause approximately 90%; of wellbore instability-related problems during the drilling operations. The formations include shales, mudstones, siltstones and claystones. When drilling under an overbalance condition in the formation without an effective flow barrier present at the wellbore wall, mud pressure will penetrate progressively into the formation 1,2. Due to the saturation and low permeability of the formation, penetration of a small volume of mud filtrate into the formation results in a considerable increase in pore fluid pressure near the wellbore wall. The increase in pore fluid pressure reduces the effective mud support that leads to a less stable wellbore condition, possibly resulting in instability3,4.
A major collaborative project between Commonwealth Scientific and Industrial Research Organisation (CSIRO) and Halliburton's Baroid product service line was undertaken to develop novel environmentally acceptable water-based drilling fluids with high membrane efficiency to help meet the future requirements of the petroleum industry. There were two principal objectives of the project. The first was the identification/development of compounds for use in water-based drilling fluids that generate highly efficient (or isolation) membranes on the borehole wall in shale formations. The second was the development of functional drilling fluid formulations with these compounds.5,6
This paper describes the development of the drilling fluids and the practical guidelines for maintaining shale stability with the drilling fluids. A specialised membrane efficiency screening equipment and associated test procedure were developed for simulation of key drilling fluid-shale interaction mechanisms, viz. mud pressure penetration and chemical potential mechanisms. More than 300 membrane efficiency screening tests were performed on Pierre II shale samples to screen and evaluate a wide range of novel compounds for their membrane generation capacity in the shale. Practical mud design guidelines that can be used to optimise the design of the new water-based drilling fluids, in terms of mud weight, salt type and salt concentration are described. These guidelines are directed at efficient management of time-dependent wellbore instability in troublesome shale formations.