Advanced Transient Modelling Identifies Optimal Well Control Methods in Slim Hole Operations

Any application of new technology requires proper preparation to ensure a safe and efficient field program. Slim hole technology requires different preparation and procedures than conventional rotary drilling techniques. Application of the mining industry’s coring techniques, small wellbore annuli, precise fluid flow measurement for kick detection, and specialized drilling fluids requires significant technical understanding and preparation. For Mobil in 1991, to prepare for a first application of Slim Hole Drilling Technology, the preparations included drilling a test well with Longyear Company’s Oil and Gas Division at Mobil’s Dallas Research Lab and using the information to prepare for two slim hole oil and gas exploration wells to be drilled in Bolivia, South America. The test well gave Mobil drilling personnel practical hands on experience with the technology and provided a slim hole test laboratory to perform extensive borehole hydraulics tests and practice well control techniques. The information gained from the test well was used to plan two exploration wells in the Madre De Dios Block in Northern Bolivia. Industry has proven the economic advantages of utilizing this emerging new technology for Oil and Gas Exploration, especially in the remote frontier areas of the world. The planning, technical, and operational points of interest are highlighted in the paper. The advantages and disadvantages of the technology observed during the wells are illustrated. Methods available to allow the technology to adapt to Oil and Gas and API standards are discussed. Many technical aspects of the application of the technology are discussed which will give an insight to the minimum technical preparation a company needs to perform to be comfortable with a first application. Areas of technology are highlighted where additional development of the technology is needed.

Both Saudi Aramco and Total Indonesia found benefits in selecting 4 in. drill pipe with streamlined double shoulder connections for the drilling of wells, for which the 3 1/2 in. drill pipe was unsuitable. Although dealing with different environments and applications, these benefits can be summarized in "successfully drilling longer slim holes with a drill string having enhanced torsional, tensile and hydraulic characteristics at a lower overall cost". For the Saudi Aramco QTF field, Extended Reach Drilling (ERD) was required with the objective to deliver pay zones located at measured depths of 18,000 ft (for the 1,500 HP rigs) and 25,000 ft (for the 2,000 HP rigs). These depths correspond to step outs ranging from 13,000 ft to 20,000 ft respectively from the drill site. For its Kalimantan field, Total was in a need of higher torsional capacity and also an improvement of the hydraulic characteristics of the drill string. Selecting a larger size of pipe was the retained option against an upgrade of the rig pump installation. The casing and drilling program remained unchanged with the drilling of a 6 in. hole after setting the 7 in. casing, adding a constraint for fishability of the string. In both cases, fishability and torque objectives made the selection of the appropriate connection essential. The selected double shouldered connection maintained a tool joint outside diameter similar to standard 3 1/2 in. drill pipe tool joints, that maintains fishing ability of the 4 in. pipe, in casing and open hole, despite the pipe size increase. The streamline connection design provides 22,000 ft-lb working torque, an outside diameter of 4–7/8 in. and an oversized internal bore that promotes hydraulic efficiency. Other important improvements include considerable gain in pipe resistance under buckling loads, increased available pressure at the bit, better telemetry for the MWD and LWD tools and improved hole cleaning and rate of penetration. Introduction Drilling deeper, slim hole wells has revealed limitations of 3 1/2 in. drill pipe traditionally used to drill the 6 to 6–1/4 in. hole sections. The level of torque that API rotary shoulder, as well as first generation double shoulder connections, can deliver does not match the new requirements for these deeper drilling programs. This increase in drill string length also puts an additional constraint on hydraulic performance. This encouraged drilling engineers to re-evaluate the drill string design requirements and select a new configuration of pipe that would respond to these new requirements. This paper addresses these pipe and connection design considerations and provides two case histories showing the benefits that were realized from using this new drill pipe design configuration. Over 1,400,000 ft of this pipe has been built to date and is in service all over the world. It is also important to mention that this new drill pipe arrangement can also be used for drilling upper hole sections eliminating the need for a string 5 in. drill pipe in many applications. Streamlined Double Shoulder Connections for 4 in. Drill Pipe There has been increasing requirements for drill pipe with improved hydraulic performance and mechanical properties to replace 3–1/2 in. drill pipe traditionally used in slim-hole drilling.

Many drilling provinces throughout the world have high reserve potential but relatively low production rates from typical wells. This low productivity may preclude economic development drilling using conventional techniques. The increasingly marginal nature of finding and producing natural gas has increased the need for technologies that reduce the cost of drilling and completing wells beyond mere incremental steps. Slim-hole drilling and completion is one technology with the potential to make a substantial impact on costs. In mid-1995, a major operating company, with support from the Gas Research Institute (GRI), undertook a three well slimhole drilling project in the Greater Green River Basin of Wyoming. Barriers to slim-hole drilling, both real and imagined, were overcome during the course of the project, and the performance capability of modern slim-hole technology was determined. Slim-hole drilling and completion will allow additional economic development of marginal areas, particularly in natural gas provinces where there is minimal need for high-volume artificial lift. Introduction and Background Early in 1995, GRI began a major project to define "Emerging Resources in The Greater Green River Basin" and to determine the optimum means of developing the area's large tight gas resource. A primary objective of this project was to identify technology that could be utilized immediately to this end. Other work underway for GRI had already identified slim-hole technology as a promising approach for reducing drilling and completion costs while maintaining well productivity. An opportunity for a three well slim-hole drilling and completion project on the Cow Hollow lease in the Moxa Arch field of Wyoming (Figure 1) was presented by a major operator, and GRI agreed to participate. The term "slim-hole" means many things to many people. Most commonly it is defined as one or more bit-sizes smaller than what is normally used in an application. The three slim production holes at Moxa Arch were all drilled with a 4 3/4-inch bit, which is slim-hole by almost anyone's definition. Interest in slim-hole drilling and completions peaked in the United States in the early 1960s, but then declined due to the absence of strong economic forces to drive development of the technology. As producers began to seriously search for methods to reduce costs in the early 1990s, interest in slim-hole technology began growing again. From the mid-1980s to the mid 1990s, the percentage of wells completed as slim holes in the United States rose from 3 to 5 percent, and the percentage is even higher for gas wells. An industry-wide survey to find barriers to slim-hole technology growth revealed that drilling was not perceived to be a large barrier. For barriers related specifically to drilling, the two topics perceived as the largest barriers were fishing and directional drilling in slim holes, as shown by the chart in Figure 2. Other topics perceived to be large barriers by the industry included mud motors, well control, and bits for slim holes. The Moxa Arch project addressed three of the top six perceived barriers to slim-hole operations, and demonstrated that, in many cases, these are only perceptions. Technology has advanced to the point that expectations and perceptions based on past history are often no longer valid. Slim-Hole Project Objectives The two major objectives of the slim-hole work were to (1) determine the current performance capabilities of modern slimhole technology and (2) determine the cost savings potential of slim-hole drilling in the Greater Green River Basin. Several areas of modern drilling technology were addressed by the project. P. 155^

After testing new slim hole drill strings that are able to perform destructive drilling and wireline coring with positive drilling achievement and positive geological data acquisition, the construction of a purpose built rig for slim hole drilling has been undertaken. It is believed that a purpose built rig will lead to substantial drilling cost breakthroughs and greatly reduce the environmental impact of the drilling operation. Reducing the Drilling Cost Environmental protection Slim Hole Prilling Practices Slim hole drilling requires a refined control and measurement of all drilling parameters. To achieve this, we need: Slim hole drilling requires a new rrange of flow parameters versus conventional practices. An original solution has been developed and is presented in this paper. Based on the above criteria the paper will detail the solutions that provide the foundations adopted to build the slim hole purpose built rig. The rig has begun operations in France in April 1994. The initial results will be available.

The Kingdom of Thailand is a net importer of both oil and gas. However, over the years a successful plan to boost local production has made the country less dependent on foreign imports. The many side benefits of this include, cheaper power generation for the Thai economy and the development of secondary downstream markets. One of the drivers for Thailand's success has been the commitment to new technology and continuous improvement employed by local operators and service companies. In fact, the role of technology in the generation of economic value within the Thai oil and gas industry cannot be overstated. This can clearly be seen by the systematic improvements made to the well construction of a market considered marginal only thirty years ago. One major step-change came in the early 1990's with the advent, and subsequent refinement of, slimhole drilling. This combined with the massive "batch-drill" concept has transformed this market into a thriving business.Several unique geologic and reservoir conditions in the Gulf of Thailand (GOT) account for this extreme technical and economic condition. A few of these issues are: small compartmentalized reservoirs with highly complex geology, multiple stacked pay sands, extremely high temperature gradient, relatively low pressure gradient, fast production declines, water breakthrough, high CO2 content of gas, and high mercury content of the oil.Improvements in all aspects of drilling played a role in the refinement of slimhole well construction1,2,3,4. Cementing has also kept pace and is one of the most important aspects of well construction and production. In the upper hole sections cement jobs need to be as logistically simple as possible and be must provide support to drill ahead quickly. In the GOT slimhole model, production tubings are cemented in place making the cement job an integral part of the completion. Indeed, one can think of the cement job as a very long production packer.This paper describes the cementing innovations achieved in the GOT within the context of the overall well construction effort. Also presented is a brief look into the future of drilling and cementing of slimhole wells.

This project used a systems approach to improve slim-hole drilling performance. A high power mud motor, having a double-length power section, and hybrid PDC/TSP drill bit were developed to deliver maximum horsepower to the rock while providing a long life down hole. This high-power slim-hole drilling system drills much faster than conventional slim-hole motor and bit combinations and holds significant potential to reduce slim-hole drilling costs. The oil and gas industries have been faced with downward price pressures since the 1980s. These pressures are not expected to be relieved in the near future. To maintain profitability, companies have had to find ways to reduce the costs of producing oil and gas. Drilling is one of the more costly operations in the production process. One method to reduce costs of drilling is to use smaller more mobile equipment. Slim holes have been drilled in the past using this principle. These wells can save money not only from the use of smaller drilling equipment, but also from reduced tubular costs. Stepping down even one casing size results in significant savings. However, slim holes have not found wide spread use for three reasons. First, until recently, the price of oil has been high so there were no forces to move the industry in this direction. Second, small roller bits and motors were not very reliable and they drilled slowly, removing much of the economic benefit. The third and final reason was the misconception that large holes were needed everywhere to deliver the desired production. Several factors have changed that will encourage the use of slim holes. The industry now favors any method of reducing the costs of producing oil and gas. In addition, the industry now understands that large holes are not always needed. Gas, in particular, can have high production rates in smaller holes. New materials now make it possible to manufacture improved bits and motors that drill for long periods at high rates. All that remains is to gather all the elements together and demonstrate the savings of slim hole drilling.

The effect of rotation on the frictional pressure loss in an annulus has been studied experimentally. A direct comparison with results obtained with a 3D CFD (computational fluid dynamics) code has been performed for laminar flow. Experimental results for three fluids are presented. In this paper we will focus on two effects of rotation in a slim hole annulus. The increase in the frictional pressure loss with high rotation rates for low viscosity fluids which is caused by the onset of centrifugal instabilities. The reduction of the frictional pressure loss with rotation for high viscosity shear thinning fluids.

Summary Slim-hole continuous-core drilling and on-site near-real-time core analysisoffer a new dimension for oil and gas exploration, especially in remote, difficult, and environmentally sensitive areas. Technologies borrowed from themining and oilfield drilling industries coupled with newly developedtechnologies were used to create a new drilling and evaluation system designedaround continuous coring, slim holes, and inverse loggingi.e., the logging ofthe actual rock as it is retrieved. This new system could cause a paradigmshift in exploration. Introduction A slim-hole well is one in which 90% or more of the length of the well isdrilled with bits less than 7 in. [less than 17.8 cm] in diameter. There aretwo basic reasons for drilling a slim hole. The first is very simple and basic:better economics. The second is borrowed from the continuous-core-miningdrilling industry: to achieve a high-percentage core recovery. Slim-holetechnology is not new. Both the explorationist and the exploitationistrecognize the possibility of using a small-diameter wellbore to reduce overalldrilling costs. In the 1950's, a major operator launched an initiative to drillslim-hole exploitation wells in Utah, Louisiana, Mississippi, Arkansas, andOklahoma, and concluded that slim-hole wells could be cost effective. However, interest in slim-hole exploitation drilling waned in the 1960's and did notre-emerge until the 1970's. A slim-hole drilling system was developed in Swedento explore and exploit some of the small, shallow reservoirs there. Dah cited a75% cost savings in this approach over conventional drilling practices. Thesuccess in Sweden encouraged practices. The success in Sweden encouragedslim-hole drilling in the U.K. and in the Paris basin in France. Costeffectiveness Paris basin in France. Cost effectiveness was again cited. Explorationists also recognized that slim-hole technology would be useful fordrilling in such remote areas as Indonesia, particularly Irian Jaya. The smallsize of the overall drilling system and the reduction in wellbore size greatlyaffected the logistical cost for drilling these wells. The greatest use ofslim-hole technology is for continuous coring in the mining industry. The onlysure way to evaluate whether an ore body is large and has a mineral gradesufficient to justify the cost of sinking shafts or embarking on a costly opencut is to obtain core to delineate the ore body. South Africa, the leader incontinuous-coring mining drilling, has developed deep gold deposits there, withsome mines below 10,000 ft [3048 m]. Continuous-coring mining drilling is sovast that it is supported by a subindustry that is totally unrelated to theoilfield drilling industry. Special manufacturers design and build drillingmachines, drill bits, tubulars, core barrels, and other required tools. Infact, the slim-hole mining drilling industry has its own association, the Intl. Drilling Federation (IDF), complete with a quarterly publication called DrillBits. Continuous-coring mining drilling operations are currently booming in theU.S. (gold and coal), Canada (mainly nickel), and Australia (various minerals). Over the years, an ongoing interest in continuously coring oil and gas wellshas existed. During the late 1950's and early 1960's, a continuous-coringsystem was developed and used to drill a number of shallow wells for oil andgas. Unique to this continuous-coring system was the design to reversecirculate the core from the well while drilling ahead. During the early 1970's, a well was continuously cored to 11,600 ft [3536 m] with the slim-hole coringsystem. This record still stands as the deepest continuously cored well in anoil and gas sedimentary environment. According to the Oil and Gas J., a 50 %cost improvement was achieved over a conventional well drilled to 6,000 ft[1829 m], and explorationists realized the advantages of continuous coring andthe slim-hole system, especially for drilling in remote areas. The concept ofcontinuous coring as an alternative exploration strategy was championed in theearly 1970's in Australia, where a series of oil and gas exploration wells weredrilled in the Canning basin. During the mid-1980's, two wells werecontinuously cored in the Permian Age Delaware basin in Texas and New Mexico. Both wells recovered more than 11,000 ft [3353 m] of continuous core. During1987–89, Amoco Production Co. drilled more than 40,000 ft Production Co.drilled more than 40,000 ft [12 200 m] of continuous core in Oklahoma, Michigan, Kansas, Colorado, and Texas. Some of that drilling is discussed inthis paper. With the apparent interest in slim-hole and continuous-coredrilling during the past 40 years, why haven't both approaches become morepopular in the oil and gas exploration and exploitation sectors? Is there aplace for slim-hole and continuous-core drilling for oil and gas explorationand exploitation? JPT P. 1184

Dome-shaped PDC cutters drill harder rock effectively : Moran, D P Oil Gas JV90, N50, Dec 1992, P46–49

A state space model for transient flow simulation in natural gas pipelines

One of the major barriers to the introduction of slimhole drilling technology to oilfield operations was perceived to be the maintenance of safe standards of well control. There were two parts to this problem. First, the reduced kick tolerance in a small annular capacity well dictated that the kick detection system must be able to detect an influx of approximately one barrel. Second, conventional well kill techniques such as the Wait and Weight Method depend on the annular pressure losses being a small fraction of the total circulating system pressure loss, such that while not causing fluid losses in the open hole, a small overbalance is maintained above formation pressure. This assumption is often not valid in slimhole wells. This paper presents a safe method of modifying commonly practiced conventional well kill techniques to take account of the high annular pressure losses and circulate out the influx in a controlled manner. Previous solutions to the slimhole well kill problem have depended upon unpracticed dynamic techniques where neither the position and volume of the influx nor the pressure applied to the wellbore are precisely known. The paper will analyse the forces occurring during a well kill operation and derive modified well kill equations. In addition, situations unique to the slimhole scenario such as the effect of annular friction pressure losses which are greater than the shut in casing pressure, their effects on MAASP and the behaviour of surface circulating systems will be discussed. The paper will go on to describe how the modified procedure is implemented. This section will include details of the well control training programme developed and the pre-kick data collection procedures established at the slimhole rigsite.

During June 1994 tests in the project "HPHT Kick Detection System Testing" were performed in Ullrigg well U-2. Experimental parameters such as influx type (liquid/ gas), gas concentration, kick injection rate, flow rate, rpm's, pipe reciprocation, pump speed changes, etc. were varied. Three kick detection systems were operating during the experiments. Two delta flow systems were supplied by Baker Hughes INTEQ (DrillByte "Kick detect" and "KDS") and one acoustic system was provided by Smedvig (Gas Kick Warner). In addition, the Petreco J-Meter flow out measuring device was also tested. A total number of 14 kicks were performed during these experiments. The majority of kicks were performed at slim hole conditions. Raw data files containing approx. 14 Mbytes of downhole pressure data from bottom P-sensor, and surface data have been gathered for further analysis. The data was of high quality and provide opportunities to improve existing well control procedures and to incorporate this knowledge into future drilling operations. This paper summarises the experimental conditions during which data were recorded, main results and operational recommendations. GAS INJECTION – STARTS.

ARG-1 exploration sour and high CO2 gas well was drilled vertically in South Sumatra, Indonesia, with a total depth (TD) of around 5000 ft-MD. The operation has been facing many challenges in drilling and completion phase; one of them is the occurrence of massive fluid losses in fractured limestone formation. Pressurized mud cap drilling (PMCD) technique is the possible solution to complete this well without sacrifice drilling fluids in enormous volume and minimize non-productive time (NPT). PMCD is one of managed pressure drilling (MPD) techniques applied in situations when drilling without return to the surface and with a full annular fluid column which is maintained above the formation. The key of successful PMCD technique is the rotating circulating device (RCD) which is used to close the annulus. Furthermore, sacrificial fluid is injected through drill string and light annular fluid is pumped down from the annulus to maintain borehole fill and prevent annular gas migration. Limestone formation was drilled with 6 in slim hole which is a contingency plan. In addition, the premature set of 7 in casing was to cover the gas zone which is located above the limestone formation. Total loss circulation occurred when drilling through upper limestone formation. Conventional combat loss techniques i.e. spot loss circulation material, gunk plug, and cement plug were used to cure the loss but none of them give significant result. It took approximately 2 months for combat loss with such common technique. In consequence, PMCD technique was decided to apply in this situation and it only required 4 days to drill until TD and ready to run 4-1/2 in casing. By successfully utilizing the PMCD technique, the company was able drastically to reduce the NPT and reach the TD successfully. This paper presents a case study of the drilling operation in ARG-1 exploration well that had massive loss circulation while using common combat loss techniques were unable to reach TD. Furthermore, it explains how drilling in PMCD mode allowed operation in ARG-1 to reach the TD after total loss of circulation was experienced and how the completion assembly was run and cemented in PMCD mode.

The transient flow analysis is fundamental to the simulation of natural gas process, in order to adjust the system to real operative conditions and to obtain the highest level of efficiency, compliance and reliability. The simulation of natural gas pipelines and networks requires mathematical models that describe flow properties. Some models that have been developed year after year based on the laws of fluid mechanics that govern this process, interpreted as a system of equations difficult to solve. This investigation describes the fully implicit finite volume method for natural gas pipeline flow calculation under isothermal conditions and transient regime. The simplification, discretization scheme and implementation equations are approached throughout this paper. The model was subjected to two evaluations: sinusoidal variation of the mass flow and opening-closing valve at the outlet of the pipeline, it is compared with two models: fully implicit finite difference method and method of characteristics. This method proved to be efficient in the simulations of slow and fast transients, coinciding the flow oscillations with the natural frequency of natural gas pipeline.

With the unconventional energy sector (e.g., shale gas) increasingly focused on precision drilling and cost-effective extraction, slim-hole horizontal well technology is gaining prominence. However, drill string dynamics in narrow, complex fluid environments are not fully understood. This study presents a novel bidirectional fluid–structure interaction (FSI) model, uniquely integrating recursive algorithms with the Moving Particle Semi-implicit (MPS) method to couple drill string–wellbore contact with drilling fluid interactions. Key findings show that drilling fluid significantly impacts drill string behavior; for instance, it can reduce natural frequencies by 20–25%, while stiff formations amplify lateral resonance risks. Optimizing fluid properties can substantially cut energy losses, though TREE is marginally elevated when viscosity exceeds the threshold (2.5 × 10−5 m2/s). The drill string typically displaces rightward, but higher viscosity can shift it left; a moderate friction coefficient aids centering. Excessive lateral displacement impairs cuttings removal, affecting fracturing. These insights enable actionable strategies: adjusting fluid viscosity and drag reducers can optimize drill string position and enhance cleaning. This research provides a framework for energy-efficient drilling in complex reservoirs, balancing efficiency with wellbore integrity and improving outcomes in the unconventional energy sector.