Differential Sticking Research Articles

Estimation of Near-Wellbore Alteration and Formation Stress Parameters From Borehole Sonic Data

Summary Highly depleted reservoirs exhibit sharply lower pore pressures and horizontal stress magnitudes than does the overlying shaly formation. Drilling through such depleted reservoirs can cause severe fluid loss and drilling-induced wellbore instability. Accurate and reliable estimates of horizontal stresses can provide an early warning of impending drilling problems that may be mitigated by appropriate drilling fluid design and drilling practices. We have developed a new multifrequency inversion algorithm for the estimation of maximum and minimum horizontal stress magnitudes using cross-dipole dispersions. Borehole sonic data for the case study presented in this paper was acquired by a cross-dipole sonic tool in a deepwater well, offshore Louisiana in the Gulf of Mexico (GOM). The logged interval spans 1,000 ft below the casing shoe. In addition, the Modular Dynamic Tester (MDT) (©Schlumberger) minifrac tests were performed at three depths in shale, thus yielding two minimum horizontal stress magnitudes. The borehole sonic data were suitable for the inversion of crossdipole dispersions at three depths in shale, as well as at a depth in a highly depleted sand reservoir. There was one depth in shale above the depleted sand where we could estimate the minimum horizontal stress magnitude with both the MDT minifrac tests and inversion of borehole sonic data. The results of the two techniques are consistent, providing encouragement for further validation of the multifrequency inversion of cross-dipole dispersions to estimate horizontal stresses. Even though the overburden stress is expected to increase with depth, both the maximum (SHmax) and minimum (Shmin) horizontal stresses obtained from the inversion of borehole sonic data are significantly smaller in the depleted sand than in the overburden shale. However, both the horizontal stress magnitudes increase again in the shale below the depleted sand. Such rapid variations in horizontal stress magnitudes cause large fluctuations in the safe mud-weight window. This challenge in drilling through the depleted sand was successfully handled by using special drilling fluid to mitigate seepage losses and the differential sticking in the depleted sand and overlying shale. We have also performed dipole radial profiling (DRP) of formation shear slownesses using the measured cross-dipole dispersions at three depths in shale and one in highly depleted sand. Analysis of radial profiles in the two orthogonal directions indicates plastic yielding or stiffening of rock in the near-wellbore region. While plastic yielding increases the shear slowness, stiffening would reduce the shear slowness.

How Much of Your Centralizer Is Left After Exiting a Casing Window in an Extended-Reach Horizontal Multilateral?

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 105766, "How Much Is Left of Your Centralizer After Exiting a Casing Window in an Extended-Reach Horizontal Multilateral? Modeling, Yard Tests, and Field Results From Alaska's West Sak Development," by E.M. Peterson, SPE, M.R. Greener, SPE, and E.R. Davis, SPE, ConocoPhillips, and D.T. Craig, Baker Oil Tools, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February. Viscous oil in the West Sak field on the North Slope of Alaska is being developed with extended-reach multilateral wells, with departure/depth ratios up to 5:1, in which slotted liners are tied back to the main wellbore with a Technology Advancement of Multilaterals (TAML) Level-3 junction system. Centralizers are necessary on the slotted liners to avoid slot plugging, reduce drag, and limit differential sticking. After three failures, a testing program was conducted on several common centralizers. Introduction The West Sak oil reservoir is part of a large viscous-oil resource overlying the Kuparuk River field on the North Slope of Alaska. Advances in drilling and a detailed study into sand management led to an economically viable project that uses extended-reach slotted liners in dual- and triple-lateral wells. Typical Well Construction The typical West Sak trilateral well dedicates a lateral to specific sand formations, typically the West Sak A, B, and D, as shown in Fig. 1. The wells are constructed by landing the intermediate casing string at 75 to 80° inclination through the lowermost sand to be completed. Then, the lowermost horizontal lateral is drilled through the intermediate-casing shoe and the slotted liner is run with a conventional hydraulic-set liner hanger and liner-top packer. With the lower lateral complete, a whipstock is set in the intermediate casing across from the middle sand, and a casing exit is milled through the intermediate casing. The casing exit usually is milled within 15° of the high side of the casing to provide the optimum direction to reach 90° inclination. The middle horizontal lateral is drilled through the casing exit, the open hole is conditioned for liner installation, and the whipstock is retrieved. The slotted liner then is run through the casing exit without guidance provided by the whipstock. A bent joint on the bottom of the liner aids finding the casing exit and guides the liner into the lateral. With the slotted liner run through the casing exit and into the lateral, the liner is landed in the casing exit with a TAML Level-3 junction. In the more difficult wells, the liner and running-string drag consume all available downweight, requiring rotation of the liner to reach total depth (TD). Following liner installation, the junction is isolated from the other laterals by use of a seal assembly stung into the liner-top packer from the lower liner and by installing another liner-top packer above the junction. Included in this run is a lateral-entry module (LEM) to provide future through-tubing lateral access. The process of setting the whipstock, milling the casing exit, drilling the lateral, retrieving the whipstock, and running the liner then is repeated for the upper lateral.

The Effect of Oxidation on Viscosity of Oil-Based Drilling Fluids

Abstract True downhole rheological properties affect equivalent circulating density, hole cleaning, barite sag, surge/swab pressures during tripping, pump pressure, and bit hydraulics. Gelation and excessive viscosity are major concerns at high temperatures. When using oil-based drilling fluids lightened by an injection of de-oxygenated air (containing small amounts of oxygen, usually around five per cent) in underbalanced drilling (UBD) operations, there is a need to be able to predict the effect of oxidation on the viscosity of the oil-based muds as a function of temperature and pressure. This paper presents the results of an experimental investigation that was aimed at establishing the effect of oxidation on the viscosity of an oil-based drilling fluid. The drilling fluid was aged for 2.5 days and for 7 days in the presence of air at temperatures ranging from 100 to 150 °C and at pressures ranging from 14 to 44 MPa. The viscosity of the drilling fluid samples after aging is compared with the corresponding fresh samples (before aging). The results show that oxidation causes an increase in viscosity. The amount of the increase depends on the amount of oxygen reacted, which is a function of temperature, pressure, and time. The higher temperatures of the reactors lead to the higher increases in viscosity. Furthermore, at higher temperatures, solid (mostly coke) formation was observed. Introduction Underbalanced drilling (UBD), in which drilling fluid pressure is lower than reservoir pore pressure, has been studied by many researchers since the late 1980s. This method can improve the financial returns on drilling a well by reducing formation damage (especially in horizontal wells and depleted reservoirs), minimizing lost circulation (especially in fractured reservoirs and depleted reservoirs), increasing the penetration rate of drilling, increasing bit life, minimizing differential sticking, reducing stimulation, and improving formation evaluation(1). The underbalanced condition is created by using different drilling fluids such as dry air, nitrogen, natural gas, mist, stable foam, stiff foam, gasified liquids, glass bubbles, and liquids. In gasified liquids, a gas is injected into the liquid to reduce the density of the drilling fluid. In these mixtures, since the pressure difference between the formation and the wellbore is relatively low (1.72 - 3.45 MPa), these drilling fluids have fewer UBD related problems such as wellbore instability and formation fluid inflows(1). These specifications have made them the most appropriate drilling fluid in UBD. The unique performance of oils makes them preferable to water as the liquid phase in gasified liquids. Oils prevent clay swelling and they are resistant to contaminants. Their rheological properties are stable at high pressures and temperatures. Also, they are highly lubricious and non-corrosive. On the other hand, to prevent downhole fires, de-oxygenated air from membrane units with maximum five per cent oxygen is usually used as the gas phase in gasified liquids(2). The presence of oxygen causes the oil in the gasified liquid to be oxidized. In this paper, the effect of oxidation on the viscosity of the gasified liquids is investigated.

Numerical Modelling of Cuttings Transport With Foam in Vertical Wells

Abstract In this study, a 1D unsteady-state two-phase mechanistic model of cuttings transport with foam in vertical wells has been developed. The model is solved numerically to predict the optimum foam flow rate and rheological properties to maximize the cuttings transport efficiency in vertical wells. Comparisons of model predictions with the field test data have shown that model predictions are in close agreement with the field test results. The numerical solution allows analyzing the effects of borehole geometry, drilling rate, foam rheological properties, gas and liquid flowing rates, and reservoir fluid influx on the cuttings transport efficiency when drilling vertical wells. Results of sensitivity analysis study are presented. Introduction The Alberta Energy and Utilities Board defines underbalanced drilling (UBD) as, "when the hydrostatic head of a drilling fluid is intentionally designed to be lower than the pressure of the formation being drilled(1)." The benefits of UBD include increased productivity by reducing formation damage, increased rate of drilling bit penetration, minimization or elimination of lost circulation, improved formation evaluation while drilling, reduction or elimination of differential pipe sticking, reduced stimulation requirements, and earlier production. Four drilling methods are referred to as UBD:gas drilling- air, nitrogen, and some hydrocarbon gases can be used as a circulating medium;flow drilling-fluid with density below the formation's hydrostatic gradient is used as circulating fluid;gas/ liquid drilling-a gas-liquid two-phase drilling fluid is used in the drilling operation; and,foam drilling-stable foams are used as cuttings transport media. Because of its variable density and good cuttings transport ability, foam is often used in UBD operations. The use of foam as a drilling fluid in many drilling operations and the results from various field cases have been well documented in the literature(2–5). Field application of the foamed drilling fluids is very often complicated because of the difficulties encountered in controlling fluid hydraulic properties. In general, compared to conventional (incompressible) drilling fluids, much less is known about the hydraulic and rheological properties of foamed drilling fluids, and even less is known about their cuttings transport capabilities. The complex flow mechanism involving in compressible drilling fluid circulation makes the determination of the optimum combination of liquid and gas injection rates very difficult. Other questions also exist, such as how to predict the bottom-hole pressure and how to combine different controllable variables in order to obtain optimum cuttings transport performance and bit hydraulics. In order to realistically simulate the hydraulics of foam drilling, factors including foam rheological properties, drag coefficient of cuttings in foam, formation fluid influx, drillpipe eccentricity, and drilling rate need to be considered in any modelling study. An example of such a modelling study is presented in this article. Literature Review The following section provides a review of literature on cuttings transport in general, the rheology of foam, and of cuttings transport with foam. Cuttings Transport Hole cleaning (cuttings transport) is one of the major factors affecting cost, time, and quality of directional, horizontal, extended reach, and multilateral oil/gas wells.

A Method for Isolating Pressure-Depleted Zones With Solid-Expandable Tubulars

Summary A method for installing solid-expandable-tubular (SET) drilling liners across pressure-depleted zones has been developed and demonstrated. High overbalance pressures are known to interfere with conventional SET expansion. "Scoping" allows an expandable liner to expand and move downward while the inner work string and expansion cone remain still. This expansion method keeps the expandable liner in continuous motion, thus reducing the risk of stuck pipe and SET failures related to differential sticking. The most common expansion method involves deployment of an SET liner on an expansion cone assembly connected to a work string. The SET is run to within 5 to 10 ft of the well bottom, then expanded hydraulically from the bottom upward. Initially, the expansion cone remains stationary when the liner is hydraulically pushed downward while expanding. The expanded liner stops advancing when it reaches bottom, and then the cone is hydraulically pushed upward as it continues to expand the liner. Scoping differs from standard expansion in that the expansion cone is initially positioned far off-bottom in the open hole between the previous casing shoe and the depleted zone. The liner is then extruded off the expansion-cone face, literally pumping the expanded liner to the bottom. The continuous movement of the expanded casing across the depleted zone reduces the risk of differential sticking. A purpose-built scoping shoe permits cementing after the pipe expansion on the same trip. This paper describes how scoping is performed and how it worked in a test well. Advantages (including time savings) and practical limitations are discussed. Additionally, the scoping shoe introduces new efficiencies to SET deployment, even if scoping is not used.

An Overview of Surfactant Applications in Drilling Fluids for the Petroleum Industry

ABSTRACT Surfactants are increasingly being used in an ever-expanding variety of applications for drilling fluids. In oil-based drilling fluids, the most well-known applications of surfactants are as emulsifiers and wetting agents. In water-based drilling fluids, there is a continually-growing variety of applications that include: - oil-in-water emulsification in base fluid formulations; - shale-swelling inhibitors to prevent wellbore instabilities; - detergency to prevent cuttings sticking to drill bit (adhesion of clay to metal parts); - prevention of differential sticking; - dispersants to inhibit flocculation of clay particles; - foaming additives, to generate high gas/water ratio foam used as drilling fluids for low-pressure reservoirs and hard-rock drilling; - defoaming additives to eliminate undesirable foam in water-based fluids; - surfactant-polymer complexes for enhanced properties in fluids for low-pressure reservoirs. This review describes historical and modern applications of surfactant technology in drilling fluids, and the impact of those molecules on drilling operations. Proper selection and application of surfactants in drilling fluids have a significant economic impact, in terms of reducing the amount of lost time and potential trouble, and have a direct consequence on overall drilling performance and results.

Borehole Stability Analysis for Underbalanced Drilling

Abstract Underbalanced drilling techniques are often considered to avoid or mitigate formation damage, reduce lost circulation risk, and increase drilling rate of penetration. However, drilling with a bottomhole pressure less than the formation pore pressure will usually increase the risk of borehole instability due to yielding or failure of the rock adjacent to the borehole. Numerous theoretical models for assessing borehole collapse and fracture breakdown risks exist. However, until recently, it has been difficult for non-specialists to use many of these models because they are not easily implemented, or because they required input parameters that are unfamiliar or difficult to obtain. A user friendly PC WindowsTM-based software package called STABViewTM has been developed to help the well designer determine the optimal range of bottomhole pressure for underbalanced drilling, i.e., the bottomhole pressures that are high enough to avoid severe hole collapse, yet low enough to avoid initiating hydraulic fractures. The software has been designed to perform rapid parametric analyses for all types of ells in most geological settings. Guidance in the selection of rock properties and in situ stresses is provided to the user with an online database of typical values and a comprehensive help utility. Applications of the software to underbalanced drilling of orizontal wells in a number of sandstone reservoirs are demonstrated. Introduction Underbalanced drilling technology is often considered for naturally fractured formations, partially depleted reservoirs that are susceptible to formation damage, heavy oil reservoirs that have been geomechanically disturbed by sand production, and in settings where improved drilling rates of penetration are required. Underbalanced drilling can have some positive effects on borehole stability. For example, shale formations containing reactive clays often suffer from hydration-related mechanical degradation, swelling, and pore pressure penetration when infiltrated by drilling muds that flow into the formation at overbalanced conditions. owever, in many cases, borehole instability can be made worse when bottomhole pressures are low. For example, low bottomhole pressures lead to an increase in shear stresses acting around the circumference of a well, hence leading to an increased risk of shear failure (Figure 1). Furthermore, the presence of steep inflow pressure gradients around a well can lead to tensile failure and spalling of the borehole wall (Figure 2). FIGURE 1: Shear yielding occurs for underbalanced conditions due to the absence of a support pressure on the borehole wall. There is usually an optimal window of bottomhole pressure that is high enough to avoid catastrophic hole collapse, yet low enough to avoid fracturing, differential sticking or unacceptable levels of formation damage. This paper describes the use of a commercial software package to identify optimal mud densities or circulating bottomhole pressures. The theory behind the stability model is briefly summarized, and its application is demonstrated with a number of field examples. FIGURE 2: Radial tensile fracturing occurs due to steep inflow gradient. Borehole Stability Modelling Background A wide range of modelling approaches are available for assessing borehole instability risks.

Using Underbalanced Drilling to Reduce Invasive Formation Damage and Improve Well Productivity-An Update

Abstract Underbalanced drilling (UBD) is becoming increasingly used as a technique to reduce significant invasive formation damage in vertical and horizontal wells to improve production rates of oil and gas, and enhance injectivity in gas and water injection situations. UBD may be a technically demanding procedure to execute in certain reservoirs and much of the benefit with respect to mitigation of formation damage may be compromised if the underbalanced drilling operation is not screened, designed and conducted in an appropriate fashion. This paper reviews common formation damage mechanisms which may occur in reservoirs and how, in certain situations, these types of damage may be reduced or eliminated through the appropriate use of underbalanced drilling technology. Various situations in which underbalanced drilling technology may result in potential significant formation damage are also discussed. Introduction Underbalanced drilling is utilized worldwide for the drilling of horizontally and vertically oriented wells to increase rates of penetration, reduce invasive formation damage and reduce problems with drilling due to lost circulation and differential sticking. Many successful descriptions of underbalanced drilling are present in the literature(1–8). However, underbalanced drilling is not a panacea for all formation damage problems in that inappropriately designed underbalanced drilling jobs may actually result in more formation damage than if a well-designed and contemplated overbalanced job had been used in the same circumstances. This paper reviews some of the technology in use at the present time in underbalanced drilling, and illustrates some of the points which operators should be aware of before embarking on an underbalanced drilling operation. What Is Underbalanced Drilling (UBD)? A rigorous definition of UBD is a condition where the circulating pressure of the drilling fluid in contact with the formation is less than the effective pore pressure in the adjacent matrix. The desirable course of action is to have this occur along the entire exposed section of the productive pay of the reservoir, resulting in an inflow of oil, water or gas (which may be contained in the matrix) into the wellbore. The produced fluids are returned to the surface along with the circulating drilling fluid. A number of descriptions of UBD exist in the literature. They can be described as follows: Overbalanced Drilling A situation in which the equivalent circulating density of the drilling mud is sufficient that, at bottomhole conditions, the drilling fluid pressure is greater than the formation pressure, resulting in an effectively "killed" state (where no inflow of formation of fluids occurs). This has been the most common technique utilized to drill wells in the past and is still the dominant technology currently used to drill many wells. Low Head Drilling Low head drilling refers to a situation where an overbalance pressure condition, similar to that described above, is maintained but with the use of lower density oil-based fluids or possibly gasified fluids to reduce the magnitude of the overbalance pressure exerted on the formation. The prime motivation is to reduce formation damage and the potential for severe invasive losses and to increase ROP. Low head drilling is still classified as a form of overbalanced drilling.

Differential-Sticking Mechanisms and a Simple Wellsite Test for Monitoring and Optimizing Drilling Mud Properties

Summary Differential sticking has a major impact on drilling efficiency and well costs. It is known to be influenced by drilling-fluid properties and other parameters, such as the characteristics of rock formations. Mechanisms of differential sticking were investigated using laboratory data and information in the literature. The knowledge gained was used to design a simple and robust device for measuring the sticking properties of drilling fluids, both in the laboratory, or at the well site. This device comprises a half-area high-pressure, high-temperature (HPHT) fluid-loss cell, modified to allow a metal sphere to be placed in contact with a growing mud filter cake. The torque required to rotate the sphere free from the mud cake is determined using an electronic torque gauge. A plot of torque against the 3/4 power of time gives a linear fit to the data. The slope of this line is indicative of the sticking potential of the mud. Laboratory and field data indicate that the test gives a good indication of mud condition and allows the user to investigate various options for reducing the sticking potential of the fluid. This information is useful both in the initial selection of mud type and in making technical and economic analyses of various mud treatment options. In addition to the laboratory evaluation described above, the sticking device has been used in several well-site tests with encouraging results. Some of these are described.

A Model To Predict Wireline Formation Tester Sample Contamination

Summary Wireline formation testers (WFTs) collect fluid samples for pressure-volume-temperature analysis through a probe set against the borehole wall. Filtrate contamination is reduced prior to sampling by either pumping the mixture of filtrate and reservoir fluid from the formation to the borehole or flowing the mixture into one or more WFT chambers. The cleanup is monitored at the surface. The time to reach the level of acceptable contamination (LAC) depends on the depth of invasion, pumpout rate, and various fluid and rock properties. Generalized guidelines predict time to first oil based on simple volumetrics but do not predict the rate of cleanup. Excessive cleanup time increases costs and the risk of differential sticking of the tool/cable. In some cases it may not be practical to attempt the operation as the LAC may take too long to achieve. A numerical simulator was used to investigate the characteristics of the contamination level versus time curve and to define the variables governing cleanup. The model was validated using data from five wells from two fields with differing rock and fluid properties. One hundred and fifty simulation runs were made with different invasion depths, flow rates, and rock and fluid properties. An equation was developed for field use that estimates filtrate contamination fw as a function of cleanout time t. An alternative approach for WFT sampling is also suggested, using not one but two probes. With this method, both cleanup time and the final level of filtrate contamination can be substantially reduced.

Underbalanced Drilling And Completion Operations to Minimize Formation Damage-Reservoir Screening Criteria For Optimum Application

Abstract Underbalanced drilling (UBD) is becoming increasingly utilized worldwide as an alternative technique to conventional overbalanced drilling to reduce invasive near wellbore formation damage problems in oil and gas producing formations. It is also increasingly used as a method for low damage completion of injection or disposal wells. Properly designed and executed underbalanced drilling operations can eliminate or significantly reduce formation damage concerns with respect to such phenomena as mud or drill solids invasion, lost circulation, fluid entrainment and trapping effects, and potential adverse reactions of invaded drilling or completion fluids with the reservoir matrix or in situ reservoir fluids. Underbalanced drilling and completion operations are not necessarily a panacea for all formation damage problems and, if an underbalanced drilling operation is poorly designed and executed, there is the potential for greater damage than if a properly implemented overbalanced operation had been used. This paper reviews reservoir characteristics and properties which should be considered to ascertain if a reservoir is a prime candidate for a UBD operation. This would include such items as reservoir lithology, matrix composition, micro or macrofracturing and heterogenous porosity features, such as large interconnected vug systems, permeability variations, heterogeneity, reservoir pressure, reservoir fluid types and other factors. A discussion of optimum operating parameters with respect to the design and execution of an underbalanced drilling operation for a particular reservoir application is provided. The selection of the appropriate type of equipment to be used (jointed pipe vs. coiled tubing), mode of underbalance condition generation (through string injection, parasite string or microannular injection), base fluid selection (oil, water or gas), gasification medium selection (nitrogen, oxygen content reduced air, air, flue gas, natural gas) and surface equipment considerations for a given UBD operation, are reviewed. Introduction Underbalanced drilling (UBD) is utilized with increasing frequency as a method to increase oil and gas well profitability by reducing invasive formation damage to maximize production rates, increase ROP to reduce drilling time and costs, and to obviate various technical problems associated with typical overbalanced drilling operations such as differential sticking and lost circulation. There have been many cases in which underbalanced drilling has been spectacularly successful in providing added value to the operators utilizing the technology. These examples have been highly publicized and have resulted to some degree in the rapid increase in popularity of the technology. Unfortunately, there have also been many instances where the results from underbalanced drilling operations have been less successful. In many cases this is not due to a deficiency in the basic technology of underbalanced drilling, but rather is related to the faulty execution or inappropriate application of the UBD technology. Not every reservoir is an ideal candidate for an underbalanced drilling operation and, in some cases, distinct disadvantages may exist in trying to execute an UBD operation in comparison to a simpler more conventional overbalanced application. This paper reviews some of the key criteria and design considerations that should be examined when evaluating a well and provides a discussion of screening criteria to be applied to ascertain if a given formation is, in fact, a viable UBD candidate.

Challenges With Jointed-Pipe Underbalanced Operations

Summary Successful underbalanced operations demand a systematic approach with integration of engineering, operations, production, reservoir, and geology. There are significant advantages to under-balanced drilling (UD). Formation damage can be minimized if proper circulating fluids and operating parameters are chosen; there is an opportunity for reservoir evaluation and characterization while drilling; lost circulation and differential sticking can be avoided, combined with improvements in drilling rate of penetration (ROP); and it also provides an alternative method of well control. This paper discusses engineering challenges and considerations for underbalanced operations using multiphase flow as well as advances made during UD with rotary jointed pipe. Excluding air, mist, and foam, underbalanced techniques with multiphase fluids are reviewed. Much of the discussion and concepts also apply to coiled-tubing underbalanced operations.

Pressure-While-Drilling Data Improve Reservoir Drilling Performance

SummaryA new downhole annular pressure-while-drilling (PWD) tool has been applied recently to assist in drilling the reservoir section on the Statfjord field, offshore Norway. For drilling success in these high-angle wells it is critical to maintain the mud weight and equivalent circulating density (ECD) within safe operating limits defined by the formation fluid, collapse, and fracture pressures. Operating outside these limits historically has led to expensive lost circulation, differential sticking, and packoff incidents. Monitoring the actual downhole pressure in real time with a PWD tool, rather than relying on inferred pressures from predictive models, has allowed the operator to stay within and to better define these operating limits. The operator used this improved hydraulics information to avoid pressure-related hole problems, to optimize drilling practices, to test hydraulics models, and to obtain a greater understanding of the formation pressure limits.

Evaluation and Selection of Drill-ln-Fluid Candidates To Minimize Formation Damage

Summary Conoco drilled and completed a horizontal well in a depleted, high-permeability oil reservoir. The formation is an unconsolidated, clean sandstone with absolute permeability over 3,300 md. The unconsolidated nature of the formation combined with its low pressure and high permeability caused concerns regarding hole stability, fracturing, excessive fluid loss, and differential sticking. To identify the best drill-in fluid (DIF) for the horizontal section, the evaluation of fluid candidates focused on both drilling properties and formation/completion-damage potential. The testing compared fluid performance in standard drilling-fluid tests, low-shear rheology at elevated temperature, dynamic fluid-loss behavior at elevated temperature, and core-flow tests. The flow testing was performed with cores from an offset well to simulate damage caused by DIF exposure and to evaluate remedial treatment options. Also, a new laboratory-scale procedure was developed to observe the tendency of prepacked screens to be plugged by DIF filter cake and unconsoli-dated formation sand. In addition to the laboratory testing, a review of the drilling and completion operations is presented, including performance of the drilling fluid at high overbalance pressure ( ≈ 2,600 psi) and the design and execution of subsequent remedial treatments. The production history is discussed and related to laboratory observations regarding cleanup and remedial-treatment effectiveness.

An Experimental Study of the Swelling Behaviour of Mudrocks In the Presence of Water-based Mud Systems

Abstract Swelling behaviour of three different mudrocks (London Clay, Oxford Clay and Fuller's Earth) of varying composition, geological ages, degree of lithification, organic matter and. expandable clay contents have been investigated in the presence of water-based mud systems (KCIICMC, Polyamine, Polyamine, + glycol and PHPA + glycol) plus water to identify the factors controlling the swelling behaviour of shales. The results show, that the degree of swelling is not directly correlatable with the proportion of swelling clay minerals in the mudrocks. Based on the experimental results, the swelling behaviour of the mudrocks depends on the composition, geological history and degree of, lithification of the mudrocks. Well lithified smectite-rich mudrock was found to show less swelling than less well lithified mudrocks with lesser amounts of swelling clays. Organic matter rich mudrock showed a greater degree of swelling than those with little organic matter, suggesting that organic matter may also influence the swelling behaviour. This investigation pro' vi des a better understanding of the swelling behaviour of mudrocks by introducing the concept of the combined action of physico-chemical and mechanical swelling processes. Introduction Swelling behaviour of different rock-fluid combinations is very important in predicting different drilling problems and determining the proper mud system to stabilize the troublesome shaley borehole environment. This characteristic of rocks is a complex function of the rock type and the mud systems and is one of the main causes of sloughing, heaving, caving and progressive hole enlargement problems in the shaley section of a borehole environment, 3). Swelling causes easy detachment of clays or shale particles both from the borehole wall and the cuttings, incorporating into the mud system as additional solid materials, and thus produces considerable changes in the rheological properties of the mud, increasing risk of differential sticking, induced fracturing and mud treatment cost. It is widely believed that smectite clay content of the mudrocks is the main culprit for excessive swelling of shale materials. In the context of drilling, this criterion of shale swelling is often unable to explain the unusual swelling behaviour of some mudrocks having little or no swelling clays. On the other hand it was found that some smectite' rich shale formations(2) have very little swelling potential compared to shales having low expandable clay content. his illustrates the role of other factors in controlling the swelling behaviour of mudrocks. Bearing this in mind an investigation was carried out to determine the factors governing the swelling behaviour of mudrocks. TABLE 1: Composition of the clay fraction <2 micron) and TOC of the mudrocks. Three different mudrocks and four different drilling mud systems plus fresh water were used for the study. The mudrocks are London Clay representing the Upper Tertiary mudrock, Oxford Clay representing the Upper Jurassic mudrock and Fuller's Earth representing the Lower Tertiary mudrock encountered in the North Sea. Some commonly used water-based muds such as KCI/CMC, Polyamine, Polyamine + glycol, water and a newly designed water-based mud system were used to assess the swelling behaviour and factors governing the behaviour of the mudrocks.

アンダーバランス掘削技術（１）

Underbalanced drilling is one of the quickly developing technologies in the world. It enables to lower the development cost by increasing the oil production per well and by avoiding the possibility of drilling hazards such as lost circulation, differential sticking. Further, production impairment reduction is significant in underbalanced drilling because no fluid invasion occurs. This paper introduces the outline of underbalanced drilling in its history, advantages and disadvantages of the technologies, various fluid systems used with, etc.

The effect of imposed electrical current on torque release at the metal-mudcake interface

Differential sticking arises in drilling operations when the drillstring embeds into a layer of mud on the borehole wall. The present work is aimed at proving the concept of an unconventional method of releasing the drill string, namely, the application of an electrical current. An instrument has been designed and constructed to measure the slippage torque at the interface between a steel disc and a filtercake prepared from a model aqueous drilling mud. Experiments have demonstrated that a cathodic current of 1 mA cm−2 reduced the slippage torque by about 50% with both mild and stainless steel. The same effect was obtained galvanically, using a magnesium sacrificial anode connected to the steel, thus dispensing with the need for an external power source. It is hoped that this effect could be used to inhibit differential sticking in aqueous drilling muds, as well as offering a fast method of stuck pipe release.

Co-polymer Beads Reduce Friction In Horizontal Wells

Introduction Divinyl benzene co-polymer beads, better known as plastic beads, have been used for reducing torque and drag in conventional drilling operations for 17 years. Over the last four years, they have also been utilized to reduce friction in horizontal wells when drill pipe is not sliding at a fast enough rate, or is not moving at all. Co-polymer beads have also gained recognition as a means of reducing friction in coiled tubing workovers. Friction is reduced by introducing co-polymer beads between the drill string and bore hole. Laboratory testing and field experience have developed methods for reducing friction through specific application techniques. Application of the beads can vary, from spotting small "pills" in specific sections of the bore hole to carrying a concentration of beads throughout the system using a bead recovery unit. Drill string drag is the incremental force required to move pipe up or down in the hole, and torque is the force required to rotate pipe. The magnitudes of torque and drag are related in any particular well, and high drag forces and excessive torque loads normally occur together. There are a number of causes for excessive torque and drag. They include:tight hole conditions;sloughing hole;key seats;differential sticking;cuttings buildup because of poor hole cleaning; andsliding well bore friction. With the exception of sliding friction, these causes are associated with problem conditions in the well bore. Although all of these conditions can occur in horizontal wells, the primary source of torque and drag in a horizontal well with good hole conditions is sliding friction. The ability to alleviate sliding friction using co-polymer beads has proven to be extremely beneficial in horizontal drilling and workover operations, including standard pipe and coiled tubing. Sliding Friction Normal contact force and the coefficient of friction between contact surfaces are the two factors that affect sliding well bore friction. Another factor, capillary attraction, must be considered in open hole situations. Capillarity is described as the relative attraction of the molecules of a liquid where it is in contact with a solid. The relative attraction of molecules leads to a force of adhesion between a solid and a liquid. The wallcake of a well bore will exert very strong capillary attraction forces on a drill string when it comes in close contact with the drill string. This is explained by the fact that the wallcake or mudcake is composed of very small particles of clay, barite, sand, or other matter, and these minute particles will have considerably more surface area exposed for wetting by liquid than would larger particles in the same section of mudcake. The smaller the particles, the more surface area exposed for liquid wetting, thus the greater the attractive capillary force exerted. The capillary attractive force could lead to the drill string adhering to the wallcake, creating torque and drag. The beads, having a larger particle size than the solids in the wallcake, reduce this adhesive force.

Assessing The Risk Of Wellbore Instability In Horizontal And Inclined Wells

Abstract Wellbore instability can lead to expensive operational problems during the drilling, completion and production of horizontal and inclined wells. This paper reviews the direct and indirect symptoms of wellbore instability, its root causes, and various empirical and deterministic modelling approaches to predicting the risk of hole collapse or convergence. In general, linear elastic models that are only concerned with stability at the wellbore wall often give overly pessimistic predictions. An alternative approach, using the extent of the "yielded" zone around an unstable wellbore and the kinematics of rock detachment, is proposed for practical risk assessments. A case history for an open hole completed horizontal well in a limestone reservoir under high drawdown is described. General guidelines for conducting field-oriented stability assessments conclude the paper. Introduction Wellbore instability during the drilling, evaluation, completion and production phases of a well has become an increasingly important concern for many operators applying horizontal well technology. Traditional conservative completion methods for vertical wells are being challenged as operators attempt to reduce well costs and still derive the improved productivity and access to hydrocarbon reserves offered by horizontal wells. More recent horizontal well innovations include the use of underbalanced drilling techniques(l), slimhole completions, side track or re-entry wells with open hole build sections(2,3), and multiple laterals from a single vertical or horizontal wellbore(4). In applying these new technologies, there are often issues posed during the well planning stage where the risk of hole collapse in the short or long term must be addressed. In many cases, the selection of an optimal strategy to prevent or mitigate the risk of wellbore collapse might compromise one or more of the following other elements of the overall well design: the rate of penetration; the risk of differential sticking; drilled cuttings and mud disposal options; hole cleaning abilities; hole size, and consequently the completion and stimulation options available; formation damage risk; stimulation requirements; the ability to log the hole; and the selection of surface sand handling facilities (where sand production is anticipated). In many cases there may be insufficient experience with a given reservoir and the desired completion, hence the prior performance of vertical wells cannot be used, by itself, to guide the well design. This paper reviews the symptoms of wellbore instability and its fundamental causes. Published approaches to wellbore stability prediction will be described, particularly those which address the most common problems faced in developing normally to slightly under pressured oil and gas fields. Emphasis is placed on techniques and conditions applicable to Western Canada where there has been a rapid pace of horizontal well development, particularly with re-entry wells. Predictive techniques applicable to build, inclined or horizontal sections of a well, during the drilling, completion and subsequent production phases, will then be described. Selected case histories from the literature are cited and an example of a wellbore stability prediction for Shell Canada's first horizontal open hole completion is described. This paper will not review all the wellbore stability models which have been developed for vertical wells.

Kinetics of the Adsorption of a Polystyrene−Poly(ethylene oxide) Block Copolymer on Silica: A Study of the Time Dependence in Surface/Segment Interactions

The kinetic aspects of polymer adsorption on surfaces are important in many practical applications. Usually, the dynamic conformational behavior of an adsorbed polymer is not measured directly but is interpreted from changes in the thickness of the layer or in the adsorbed amount. Infrared spectroscopy is now used to present direct evidence of the dynamic behavior of segment/surface interactions. The time dependent behavior of the segment/surface interactions of a PS−PEO (polystyrene−poly(ethylene oxide)) block copolymer adsorbed on silica particles is reported. Three distinct zones are identified. In the first region, the polymer adsorbs on vacant sites on the surface and does not undergo any rearrangement. The relative number of surface-anchored PEO and PS segments is dictated by the differential sticking enthalpies rather than the geometric size of each block. In the second region, the surface sites are fully covered and fresh polymer arriving at the surface is accommodated by a rearrangement of the existing adsorbed polymer layer. The more weakly attached PS segments are displaced by PEO units of the incoming chains. In a final stage, a slow rearrangement of the adsorbed polymer layer occurs. The adsorbed PS segments are sacrificed for additional adsorbed PEO segments, and the adsorbed layer tends toward the brush conformation.