In April 2005, the Chevron Joint Industry Participation Project (JIP) on Gas Hydrates organized a drilling and coring expedition to potential gas hydrate sites in Atwater Valley and Keathley Canyon in the Gulf of Mexico. In support of these activities, methods were developed to predict the mechanical and phase change stability of boreholes drilled in sediments containing gas hydrates. Models of mechanical failure and downhole temperature were constructed from seismic and log data for the wells in Atwater Valley and Keathley Canyon. Model results were compared with LWD caliper, image, and temperature logs in three boreholes. LWD logs were also used to assess drilling performance. Mechanical failure models compared favorably with deformation features observed in image logs in all three wells. An excellent match was also obtained between the modeled and measured downhole temperatures in Atwater Valley. However, for reasons that remain unknown, temperatures observed in the Keathley Canyon wellbore were generally lower than those predicted by the model. Time-lapse analysis of LWD data revealed that the equivalent circulating density (ECD) in Atwater Valley became abnormally high and coarse-grained solids were falling into the BHA annulus from uphole causing packoffs. These packoffs eventually caused the rotary to stall. Some evidence that the packoffs were caused by shallow water flows discharging large quantities of sand into the wellbore was found. Post-drill temperature simulations indicated that the LWD boreholes in Atwater Valley and Keathley Canyon were sufficiently cool to prevent hydrate from dissociating, owing in part to successful management of circulation rates in the borehole. It was also shown that loop currents at Atwater Valley helped to reduce the risk of dissociation. Introduction Gas hydrates are crystalline substances consisting of molecules of gas (e.g., methane, ethane, H2S) locked in a cage of ice1. They occur continentally in the sediments of permafrost regions such as in Alaska or Siberia, or close to the mudline in deepwater marine sediments, such as in the Gulf of Mexico or the Nankai Trough. Gas hydrates dissociate into water and gas when sufficiently heated or depressurized. Since vast amounts of gas are thought to be locked in sediments containing gas hydrates, there is growing international interest in gas hydrates as an energy resource2,3,4,5. Boreholes drilled in sediments containing gas hydrates are susceptible to a variety of instabilities. Thermal disturbances caused by drilling can lead to dissociation of gas hydrates. Instances of blowouts accompanying dissociation have been documented in the literature, particularly in permafrost regions6. It is likely that such incidents are under-reported, since operators are not always aware that they are drilling in gas hydrate zones. Since gas hydrates can enhance the strength of sediments, either by cementing the grains, or by acting as load bearing members in the pore space, the dissociation of gas hydrates during drilling can lead to a dramatic loss of mechanical competence. Furthermore, the expansion of gas accompanying dissociation may result in an abrupt increase in the pore pressure7 thereby weakening the sediment further. Thus sediments undergoing dissociation may be in an exceptionally weakened state when compared with surrounding formations.

Summary This paper describes continuing efforts to develop a water-based drilling fluid that will provide the osmotic membrane behavior and wellbore stability of an oil-based drilling fluid. A pore-pressure-transmission technique in use for several years as a tool to measure osmotic behavior has been refined for improved measurement of changes in shale permeability and pore pressure in response to interaction with drilling fluids. Conventional invert-emulsion and water-based drilling fluids containing selected additives were tested with outcrop and preserved shale specimens using an innovative screening method. Observed pressure differences across each shale specimen were compared with the values predicted by osmotic theory. From this comparison, an empirical concept of "membrane efficiency" was developed. Three distinct types of "membranes" are postulated to describe the interaction of various drilling fluids with shales. Type 1 membranes are generally characterized by coupled flows of water and solutes between fluid and shale. Type 2 membranes greatly reduce the near-wellbore permeability of shale and restrict the flow of both water and solutes. Type 3 membranes transport water more selectively, but shale permeability and fluid chemistry may alter performance measurements. Invert-emulsion fluids tend to form efficient, Type 3 membranes; however, under certain conditions, these fluids can yield lower capillary pressures than described previously and invade the interstitial fabric of high permeability shales. Several water-based mud formulations were prepared that achieve approximately one-quarter to one-half the measured osmotic pressure of a typical oil-based mud (OBM). Fluid additives that supplement or reinforce a Type 1 membrane, such as saccharide polymers (especially in combination with calcium, magnesium, or aluminum salts), can induce relatively high efficiencies. As expected, fluids that form a Type 2 membrane, such as silicate and aluminate muds, provide the highest membrane efficiencies. Basic Osmosis Concepts Leakiness governs the effectiveness of osmosis and determines efficiency for a semipermeable membrane, which restricts the passage of solutes while the solvent is relatively unrestrained. Leakiness may more accurately describe a phenomenon for which the term "selectivity" has been applied previously. Membrane efficiency in restraining the passage of solutes is quantified by the reflection coefficient, sigma. The "reflection" analogy comes from an optical model adopted by researchers. The model assumes a semipermeable membrane analogous to a mirror - fully or semisilvered. All solutes of a solution to which a membrane is exposed will be fully or partially "reflected" by the membrane. An ideal semipermeable membrane (i.e., one that allows passage of the solvent only) has a reflection coefficient, s, of 100% or 1. Nonideal membranes, which allow partial passage of solute, have reflection coefficients of less than 1 and are, therefore, referred to as "leaky." Clay-based materials have intrinsic membrane behavior with reflection coefficients between 0 and 1, depending on the fluid contacting the clay surface. A high-permeability sand, on the other hand, does not exhibit semipermeable properties, and its reflection coefficient is essentially zero. For a system at thermal and electrical equilibrium, osmosis across a semipermeable membrane consists of solvent transport (usually water) from higher to lower water activity [i.e., from the side containing a lower concentration of solute (dilute) to the side with higher concentration of solute (concentrated), such as a salt, sugar, or glycol]. This flow of pure solvent is commonly referred to as "chemico-osmosis" or "chemical osmosis." Solvent flow will continue unless or until osmotic pressure is balanced by hydraulic pressure. For an ideal semipermeable membrane, that is the extent of osmosis. For a leaky membrane, however, solute species will also flow and can flow in both directions1–3; furthermore, hydrated species will carry solvent with them, leading to countercurrent flow of water and solutes.4,5 For a shale in contact with a typical salt-based aqueous drilling fluid, water will flow from the shale into the drilling fluid, but opposing, hydrated cations and anions will flow from the drilling fluid into the shale. Additionally, hydrated salt species in the pore network of the shale will tend to flow into the drilling fluid. Further complicating the picture is the resulting exchange of ions on the clay. These "coupled flows" that characterize osmosis complicate predicting membrane efficiency.5 Soil scientists and drilling-fluids researchers commonly observe osmotic pressure development as a developing hydraulic head in an atmospherically pressured environment. Measured osmotic pressure curves typically develop, as presented in Fig. 1. The slope of the pressure development curve of an ideal membrane approaches zero, and the slope of a nonideal membrane becomes negative after a period of equilibration. The clays composing shales are natural membranes made up of combinations of two basic structural units. The silica tetrahedron and alumina octahedron are assembled in sheets. Clay minerals are characterized by differences in the stacking of these sheets and the manner by which the sheets are held together. Differences in the crystal structure of the sheets (isomorphic substitutions) are commonly seen as the replacement of Al3+ for Si4+ in the tetrahedral sheet and of Mg2+ for Al3+ in the octahedral sheet. These substitutions cause clay surfaces to have a net negative surface charge. Electrical neutrality is preserved by attraction of cations, which are held between the layers and at the surface of the platelets. This electrostatic attraction results in a charged clay surface and a concentration of counter-ions that diminishes with distance from the surface. The charged clay surface with the counter-ions in the pore water form the diffuse double layer. The double layer is affected by changes in salinity, pH, temperature, and valence of counter-ions.1 The ability of clays to act as membranes is a consequence of overlapping double layers of adjacent clay platelets. Compaction, as occurs during the formation of shales, results in a higher concentration of cations and a reduced concentration of anions in the double layer with respect to an equilibrium solution. The aqueous environment of narrow pores can be overwhelmed by the merged, opposing double layers. Diffusion of anions through the narrow aqueous film is inhibited because the anions are repelled by the net negative charge of the platelets. Advection (the flow of solutes and heat that accompany the bulk motion of a fluid) is restrained, and the effect is known as the "Donnan Exclusion."4

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Hole cleaning is often more difficult during drilling of inclined wells. The resulting poor removal of cuttings can lead to problems such as borehole pack-off and excessive ECD, which are both difficult and expensive to resolve. Fluid sweeps are commonly implemented when normal circulation cannot adequately remove cuttings from the borehole. Field reports have indicated that specialized fibrous-type materials enhance cleaning performance when added to fluid sweeps. Yet, understanding of the behavior of this improvement remains inexact. This paper presents a comparative experimental investigation of the hole cleaning performances of fiber sweeps, conducted with different drill pipe rotation speeds and fiber concentrations. Experiments were carried out in an inclined flow loop apparatus with an inner rotating drill pipe. The hole cleaning performance of fiber-containing sweep fluids using different fiber concentrations (0%, 0.05%, 0.1%, and 0.2%, by weight) and varying drill pipe rotation speeds (0 to 90 rpm) was evaluated. Sweep efficiencies were compared in terms of the measurement of cuttings bed heights before and after circulating the sweep fluid.The results indicate that significant improvement associated with higher fiber content requires a commensurate increase in drill pipe rotation speed. With lower or no pipe rotation speed, increasing fiber concentration yields less dramatic returns. Pairing high fiber content with rapid pipe rotation resulted in enhanced performance over the control sweep, which contained no fiber, but relatively low concentrations did not surpass the control.With the increasing need in the industry to drill extended reach or otherwise inclined wells, there is greater potential to develop problems stemming from inadequate hole cleaning. This research gives insight into the specific interaction of sweep fiber and pipe rotation with the cuttings bed, and with each other. Deeper understanding of fiber sweeps would inform infield decisions when dealing with poor hole cleaning.

Thermal effects on wellbore stresses can have a significant impact on effective fracture gradients. Changes in wellbore temperatures caused by various drilling operations provide for these thermal effects. For example, circulation on bottom usually results in lower bottom hole temperatures than the static geothermal temperature. This cooling effect reduces the wellbore stresses resulting in lower effective fracture gradients. Minimizing the cooling effect by increasing wellbore temperatures can increase effective fracture gradients and the corresponding pore pressure/fracture gradient margin avoiding costly lost circulation and additional unnecessary casing points. This paper presents results from leak-off tests taken at various temperatures which demonstrate the thermal effect on formation stress. This paper also examines the effects of operational factors on wellbore temperatures to minimize the cooling effect and/or increase effective fracture gradients. Software developed for thermal simulation of various drilling operations was used to perform the analysis. Introduction An investigation of historical lost circulation events, particularly in deepwater environments, resulted in considering the thermal effects on formation stress as a possible cause. A test was performed where leak-off-tests were taken at varying temperatures to confirm that the results would indeed be affected by wellbore temperature. The results of this test are presented in this paper. Subsequent analysis of historical lost circulation events in several deepwater wells indicated that at a minimum, there was at least a strong correlation between wellbore temperatures and a significant number of these lost circulation events for which several examples are presented in this paper. An understanding of the various factors that influence wellbore temperature was then needed to develop ideas as to how wellbore temperature might actually be managed to potentially prevent what can be referred to as thermally induced lost circulation. Thermal simulation software based on work by Mitchell and Wedelich1 was used to run a sensitivity analysis on a deepwater example well of the various controllable factors that influence wellbore temperatures. The results of this analysis are also presented in this paper. Thermal Effects on Formation Stress Timoshenko and Goodier2 presented an elastic theory which describes the effect of thermal stresses around an infinitely long cylinder containing a circular hole. In it, they showed that heating the inner wall of the cylinder will result in an increase in the compressive forces around the hole. Perkins and Gonzales3,4 discussed an analytical solution to the thermoelastic problem, showing that injecting large volumes of liquid that is colder than the in-situ reservoir temperature can significantly reduce the fracturing pressures in the formation. Tang and Luo5 presented model predictions of the effect on the near-wellbore stresses of differences in temperature between the mud in the wellbore and the formation. Figure 1 shows the results of their simulation of a 15 hour mud circulation period followed by a 15 hour noncirculating period. They predicted a tensile stress of 1015 psi around the wellbore after the 15 hour mud circulation period, followed by a gradual reduction in the tensile stress during the non-circulating period.