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

fax 01-972-952-9435 ___________________________________________________________________________

Specialty drilling fluids, described by mud companies as rheologically flat, constant, or continuous, were introduced for drilling in deepwater less than 10 years ago. As used, the terms describe a rheological profile which is relatively flat or continuous only when compared to that of a conventional non-aqueous fluid. These specialty fluids have been shown to reduce plastic viscosity by 50-70% at seabed temperature and provide more consistent yield point, 6, and 3 rpm rheological values across a broad range of temperature. The properties are maintained primarily by use of temperature sensitive associative polymers.First generation associative polymers are efficient but have limited temperature stability. Controlled 16 hour dynamic exposure shows that the temperature stability of the highest quality associative polymer in use by most mud companies is less than 210°F. This modest temperature stability and resulting thermal degradation of the polymer and mud properties has begun to limit application in hot wells. It has been claimed that early generation polymers can be used when bottom hole temperature exceeds 250°F However, it has been necessary in some cases, before logging or completing a well, to spot 50-100 barrels of drilling fluid supplemented with organoclay as a "pill" in the open hole. This is needed if thermal damage and loss of rheological properties are expected to occur due to extended exposure to bottom hole temperature beyond the thermal stability of the associative polymer selected.When a deeper higher angle well with bottom hole temperature of 250-350°F is considered, the probability for rapid thermal degradation increases and a more stable polymer chemistry is preferred. In 2010 a second generation associative polymer with claimed temperature stability of 350°F was introduced for use in the field.Laboratory tests confirm significantly improved temperature performance by the novel second generation associative polymer. Field experience has shown that the new polymer is essentially interchangeable with an earlier version without significant change in rheological properties at lower temperature. A detailed study and discussion documents how the new second generation polymer compares to the original polymer in terms of indicative cost, performance, and potential for application in hotter environments.

The issue of drilling depleted zones is increasing in importance as more wells are drilled in mature fields. These zones are typically produced or producing reservoirs overlaid and interbedded with shale layers. Pressure overbalances have been reported as high as 13000 psi but are more typically of the order of a few thousand psi. Wellbore stability problems associated with drilling in these zones can be linked with drilling-induced and pre-existing fractures. We describe an approach that links a fracture-fluid-flow model with fluid rheology over a wide range of flow rates and flow behavior in a fracture generation apparatus. The understanding gained is used to develop guidelines for minimising losses into fractures. A numerical fracture simulation scheme with Perkins-Kern-Nordgren (PKN) geometry and flexible rheology of the invading fluid predicts fluid volume lost as a function of time. The drilling environment - differential pressure, fracture gradient, pore pressure and rock properties - can be varied. The effect of fluid rheology on fluid loss rate is demonstrated under various combinations of the parameters relevant to depleted zone drilling. Drilling fluid rheology was investigated in shear flow over the shear rate range 0.001 - 1000 s−1, and in transient flow. Most fluids exhibited shear-thinning and thixotropic behavior that could not be described in terms of PV and yield point (YP) alone. Constitutive rheological models were used to describe the data for input to the simulation model. A wide range in transient behavior was found, and it forms the basis of an experimental test to rank and select fluids to minimize losses in fractures. The fracture generation apparatus enables a fracture to be initiated in a rock core, closed and then re-opened. We evaluated a suite of water-based and oil-based fluids and lost circulation materials, some of which show unexpected increases in the reopening pressure. Introduction The issue of drilling depleted zones is increasing in importance as more fields mature. These zones are typically produced or producing reservoirs overlain and interbedded with shale layers. Pressure overbalances have been reported as high as 13000 psi in the Gulf of Mexico1 but more typically are on the order of a few thousand psi. Drilling problems in these zones can be broadly categorised into three main areas: Wellbore StabilityThe presence of normally pressured shales means a higher mud weight is required to prevent collapse even when drilling in the depleted zone.The drilling profile with regard to bedding must be considered both with regard to the overlying shales and weakening of the reservoir rock itself that can result from the depletion process.There can be an issue with mechanical sticking from creeping shales if mud weights are not maintained high enough. Proper levels of inhibition need to be maintained to prevent chemical swelling of shales.If salt structures are being drilled, high salt concentrations are needed to prevent dissolution; therefore it is difficult to lower the mud weight for the depleted zone. Lost Circulation into Pre-Existing and Drilling-Induced fracturesA high mud weight can result in fracturing of rock already weakened by the depletion process.The loss of fluids into fractures is costly and may lead to well control problems.There could be loss of productivity with blocked fractures.Fractures can increase overall wellbore stability problems

Conversion of drilling mud to oilwell cement has advanced from an unpredictable laboratory curiosity to a practical reality. Recent field introduction of polymer dispersants, organic accelerators, and an alternative cementitious material have provided two refined and practical conversion methods. Each method claims universal applicability plus performance superior to that of conventionally mixed and pumped Portland cement. Both blast-furnace-slag (BFS) and Portland cement are used for drilling-mud conversion. Portland and BFS mud conversions can use the same recently developed polymer dispersants, filtration-control materials, defoamers, and other additives that are typically used to treat high-temperature, highly-saltcontaminated drilling muds. Experience in the field and laboratory has demonstrated that conversion with BFS or Portland cement is essentially one technology from a pilot-test and application standpoint. While use of these two materials reflects essentially one technology, distinct performance and cost differences exist. These differences define the specific economic application advantages and must be considered when a decision to use BFS or Portland cement is made. Rational selection of mud-to-cement conversion depends on a detailed economic comparison of basic materials, logistics, and equipment availability.