Summary During laboratory drilling tests in a permeable sandstone, the effects of pore pressure and mud filtration on penetration rates were measured. Four water-based muds were penetration rates were measured. Four water-based muds were used to drill four saturated sandstone samples. The drilling tests were conducted at constant borehole pressure while different backpressures were maintained on the filtrate flowing from the bottom of the sandstone samples. Bit weight was varied also. Filtration rates were measured while circulating mud during drilling and with the bit off bottom. Penetration rates were found to be related qualitatively to the difference between the filtration rates measured while drilling and circulating. There was no observed correlation between standard API filtration measurements and penetration rate. Introduction A better understanding of the effects of pore pressure and mud filtration on penetration rates and how these effects relate to standard API filtration properties was sought during full-scale laboratory drilling tests in a permeable sandstone with four different laboratory-prepared muds. Measurements of penetration rate and filtration rate were made as mud type, bit weight, and backpressure on the filtrate produced from the sandstone samples were varied. Other parameters-such as rock type, bit type, rotary speed, flow rate, borehole pressure, confining pressure, overburden stress, mud temperature, and penetration interval were held constant. The filtrate volume vs. time or filtration rate measured while drilling is herein designated "drilling" filtration rate. "Circulating" filtration rate refers to filtration rate measured with the bit off bottom and with mud circulating in the borehole. From the measured filtration rates, pressure drops through the rock samples were calculated pressure drops through the rock samples were calculated using Darcy's law. After the pressure drops were subtracted from the measured total drop across the rock (borehole pressure minus backpressure), the pressure drops across the mud filter cake at the bit/rock interface were determined. The test results are presented in terms of these pressure drops. pressure drops. Changes in penetration rate with bit weight and pressure drop across the filter cake were examined. The relationship between penetration rate and filtration rate was determined. An attempt to correlate the drilling test results with standard API filtration properties was also made. Drill Bit, Rocks, and Muds A 77/8-in. [20.07cm] diameter Smith F-3 bit (IADC 5–3-6) with three 10/32-in. [0.84-cm] diameter nozzles was used for the drilling tests. The bit had a pressure drop across the nozzles of approximately 900 psi [6205.3 kPa] at 240 gal/min [15.14 dm3/s] for the 9.5-lbm/gal [1138.35-kg/m3] mud used during the tests. Four Berea sandstone samples (15.5-in. [39.37-cm] diameter by 36-in. [91.44-cm]) length were drilled. Before drilling, the Berea sandstone samples were evacuated for a minimum of 24 hours, saturated with tap water, weighed, and stored under water. From the saturated weight, bulk volume, porosity, and grain density, water saturation was then calculated. The samples were saturated between 95 and 100%. After the samples were jacketed between steel end caps, the top end cap was filled with water to maintain the saturation. The Berea sandstone samples had a grain density of 2.65 gm/cm3 [2650.0 kg/m3], a porosity of 20%, an unconfined strength of 9,000 psi [62 052.8 kPa], and a permeability of 0.2 darcies. The four water-based drilling muds tested included a low-solids, nondispersed mud (LSND); a low-solids, nondispersed mud with sodium polyacrylate filtration control additive (LSND-SPA); a dispersed (DISP) mud; and an oil emulsion (OIL EMUL) mud. Approximately 120 bbl [19.08 m3] of the LSND mud was prepared first. The LSND mud had a relatively high API filtration rate of 0.92 cu in./30 min [15 cm3/1800 s]. Various materials were added to portions of the LSND mud to obtain the LSND-SPA, DISP, and OIL EMUL muds, which had relatively low API filtration rates of 0.43 cu in./30 min [7 cm3/1800 s]. Composition of the muds is given in Table 1. The methods used to reduce the API filtration rate of the LSND mud reflect typical choices that are available when filtration reduction is necessary during drilling. Ferguson and Klotz performed filtration experiments while drilling with various mud types; Krueger later studied the effects of common filtration control additives on filtration while circulating. Many of these additives require significant amounts of shearing and circulating time to reach full effectiveness. In view of this, the performance of these additives in laboratory-prepared muds performance of these additives in laboratory-prepared muds may differ somewhat from the performance that would be observed in field-conditioned muds. Mud properties were measured before and after each drilling test (Table 2). JPT P. 1671

In many deepwater plays around the world, salt formations overlie prolific reservoirs containing billions of barrels of oil. Drilling into these reservoirs requires the successful penetration of the challenging salt layers. Based on experiences in key deepwater basins, this paper reviews the fluids and techniques used to drill through salt formations. Salt formations are unique. Salt has little porosity and permeability. It can flow plastically through other geological rock beds under stress with "salt creep" resulting in wellbore size reduction and casing collapse. Salt can also dissolve in water necessitating the salinity of a water-based fluid be kept near or at saturation to avoid or minimize wellbore enlargement that can lead to poor cementing of the casing and deficient zonal isolation. In spite of the aforementioned issues, salt formations are drilled successfully around the world, and drilling fluids play a vital role in a successful drilling operation. A downhole simulator cell (DSC) has been found to be a key tool in assessing the effect of drilling fluids on salt formations by drilling salt cores at in-situ conditions of temperature and pressure while monitoring the core and fluid interactions. This paper combines a downhole simulation cell (DSC) testing and data from previous literature to provide a comprehensive overview of drilling fluids interactions with salt formations. This dialogue combines the experiences of drilling salt as seen from a drilling fluids perspective into one publication. Three generalized fluids are evaluated: riserless water-based fluid (WBF), high-performance water-based fluid (HPWBF), and synthetic-based fluid (SBF). Performance criteria used to evaluate fluids include rates of penetration (ROP), hole cleaning, wellbore stability and washout minimization. Environmental compliance and system strengths and limitations are outlined. Topics include evaporite mineral types and drilling challenges including exit strategies and tar beds.

Summary. Previous attempts to predict the effects of drilling fluids on borehole stability in shale have been unsatisfactory. This paper describes laboratory equipment capable of simulating downhole conditions to permit evaluation of drilling fluids by testing the alteration of natural shale specimens when drilled and exposed to drilling fluid under an annular flow regime for an extended period of time. The paper discusses ramifications of the shale alteration relative to such operational problems as torque, drag, and stuck pipe. Introduction Borehole stability is a critical factor in the cost of drilling and completing a well. Some of the problems caused by an unstable borehole are high torque, drag, bridging, and fill; stuck pipe; difficulty with directional control; slow rate of penetration, high mud costs; cementing failures and high cementing costs; and failure to obtain logs and poor log interpretation. Most borehole instability occurs when water-based muds are used to drill shale formations. Such borehole instability is related to hydration and dispersion mechanisms, which in turn are related to the interaction of shale with the drilling fluid. Laboratory and field studies have shown that shale hydration and borehole instability can be avoided by the use of oil mud with activity of the emulsified internal water phase equal to or less than the in-situ activity of the water in the shale formation. Environmental considerations, however, often preclude the use of oil mud. Efforts to characterize shales and to predict stability in different types of water-based drilling fluids have met with little success. This lack of success can be attributed to the complexity of the shale/drilling-fluid interactions that include surface hydration, osmotic swelling, cation exchange, anion adsorption, and alkali-alteration phenomena. Borehole conditions created by these interactions, in turn, depend on exposure time, temperature, and stresses of the shale, as well as shear stress and shear rate of the fluid at the shale surface. With so many factors involved, the tendency has been to rely on simple tests, such as those for shale swelling by Chenevert, shale dispersion by Anderson and Edwards, and capillary suction time by Wilcox and Fisk as guides to drilling-fluid selection. While useful as part of an overall laboratory or field study, these tests of unconfined, unstressed shale at ambient conditions of temperature and pressure can be very misleading if used alone to predict the effects of a drilling fluid or additive on shale stability. A problem as complex as shale stability can best be addressed by studies of shales exposed to drilling fluids under simulated downhole conditions. Previous studies of this general type have provided much-needed guidance, but each study has failed to simulate one or more significant parameters. For example, the model borehole studies reported by Darley and Clark et al. simulated vertical stress, radial stress, and mud pressure, but not downhole temperatures. Studies reported by Simpsons included simulation of downhole temperature, but not vertical stress. With laboratory evaluations that are limited in scope and often misleading, the present tendency of drilling personnel is to look for improved shale stability from water-based drilling fluids on a trial-and-error basis. A research project was organized under the auspices of the Drilling Engineering Assoc. to develop a laboratory method to predict shale stability under simulated downhole conditions. The downhole simulation cell (DSC) equipment described below resulted from that program and now provides the industry with the means to evaluate drilling-fluids performance without the time, expense, and risk of a series of blind field trials. DSC Equipment The DSC equipment shown schematically in Fig. 1 and by photograph in Fig. 2 provides laboratory simulation of overburden stress and confining pressure, as well as downhole temperature, fluid circulating pressure, and shear rate at the wall of the hole during drilling and circulating through a rock specimen. Downhole conditions can thus be simulated for a variety of studies of fluid/rock interactions. For example, in addition to the borehole-stability studies discussed in this paper, the DSC equipment has been used to study dynamic filtration during drilling of permeable rock. Key elements of the DSC system are identified in Fig. 1 and discussed below. Not indicated in Fig. 1 is the PC data-acquisition system for monitoring drilling parameters and collection of time-based information during the testing. Sample Vessel and Drilling Subsystem. The sample vessel, shown in the left center background of Fig. 2, allows the use of rock specimens up to 7 in. [17.8 cm] in diameter and 9 in. [22.9 cm] in length. A hydraulic ram is used to provide overburden stress on the specimen, with a maximum stress of approximately 10,000 psi [69 MPa] possible on specimens with 6.4-in.[16.3-cm] OD. Heat-transfer oil is used as confining fluid inside the specimen chamber. The maximum allowable confining pressure is 7,000 psi [48.3 MPa]. A bit-position/drilling-force hydraulic cylinder, which provides bit motion and force on bit during drilling, is used to drill completely through the rock specimen. Rotation of the bit shaft is provided by two hydraulic motors. Mud flow through the bit is obtained by means of a swivel seal in the vessel base. Provisions are made for mud circulation through the specimen after the hole has been drilled and the bit and drill shaft have been retracted. Mud is circulated through the ram piston on the top of the vessel. Cuttings removal and mud return circulation are provided by 0.75-in.[1.9-cm] tubing going to the cuttings catch vessels. This vessel is heated with 480-V band heaters. Copper coils embedded in the outer periphery of the vessel provide cooling. Water is flowed through the cooling coils at the end of the shale exposure testing to cool the specimen sufficiently for removal from the vessel. A caliper assembly was devised to measure borehole enlargement while testing was in progress. The mode of rock deterioration usually observed, however, has been softening or weakening of the shale, rather than hole erosion. This finding led to the use of the caliper shaft as an assembly placed in the hole to create an annulus for flow during the test, without extensive use of the caliper function. The annular velocity and circulating information in Table 1 is based on the 1.0-in. [2.54-cm]diameter of the caliper assembly and a 1.25-in. [3.18-cm] hole diameter. Circulation Pump. A balanced piston pump, designated "mud pump" in Fig. 1 and shown in the center of Fig. 2, is used to circulate the fluid through the rest of the system. The pump consists of a liner with a reciprocating shaft and attached piston. The shaft motion is provided by a large hydraulic cylinder. Four air-actuated valves are controlled electronically to provide circulation of the drilling fluid in a single direction with a minimum of pressure surging.

fax 01-972-952-9435. AbstractProblems encountered while drilling shale formations are a major factor in the cost of oil and gas wells. A principal cause of the problems has been shown to be the transfer of water and ions from water-based drilling fluids to shale formations. Prior studies have documented two driving forces involved in such transfer. One is the hydraulic pressure differential between the drilling fluid and shale pore fluid. A second is a chemical osmotic force dependent upon the difference between the water activity (vapor pressure) of the drilling fluid and that of the shale pore fluid under downhole conditions. Generally unrecognized is another driving force, diffusion osmosis, which is determined by the difference in concentrations of the solutes in the drilling fluid and shale pore fluid. Diffusion osmosis results in transfer of solutes and associated water from higher to lower concentration for each species, opposite to the flow of water in chemical osmosis. If the diffusion osmotic force exceeds the chemical osmotic force, invasion of ions and water can increase the pore pressure and water content of the shale near the borehole surface. Additionally, the invading ions can cause cation exchange reactions that alter the clay structure in the shale. All of these effects tend to destabilize the shale.Destabilizing ionic reactions within a shale can be minimized if a suitable nonionic polyol (such as methyl glucoside) is used to reduce the activity of a fresh-water drilling fluid. In certain situations the addition of salt to such a fresh-water drilling fluid to obtain further reduction of water activity can cause an increase in the diffusion osmotic force that offsets some, or all, of the desired increase in chemical osmotic force. This now is recognized to have probably been a factor when sodium chloride was included in the formulation of a methyl glucoside drilling fluid used with moderate success for drilling in the Gulf of Mexico.Chemical osmotic effectiveness can be improved by emulsification of a non-aqueous phase in the drilling fluid. A fresh-water drilling fluid containing methyl glucoside for activity control and emulsified pentaerythritol oleate prevented hydration and maintained stability of Pleistocene shale from the Gulf of Mexico. Drill cuttings from such a drilling fluid should be environmentally acceptable for discharge at offshore or land locations.

Laboratory data are presented showing that lime muds utilizing a polysaccharide deflocculant are very effective in combating dispersion of shale particles when compared to several commonly used types of water based muds. Similar studies using Wyoming bentonite particles are reported snowing that potassium hydroxide results in less clay dispersion than sodium hydroxide when used for alkalinity control of a lime mud deflocculated with polysaccharide. While the potassium is shown to be reactive with clay particles, the presence of lime in the mud leaves more potassium ion available to react with shale exposed in the wellbore and protect against borehole instability. Field results are reported showing that potassium ion concentrations of 1,000 to 4,000 mg/L have been adequate in potassium/lime muds containing polysaccharide deflocculant to provide good borehole stability and low mud maintenance costs.