Shale swelling is a serious issue in water-based muds (WBM) as it may lead to stuck pipe, shale sloughing and decreased rate of penetration. Linear Swell Meter (LSM) testing is one of well-known laboratory tests used to characterize shale swelling. This paper describes how the time-dependent swelling response from LSM is modeled to extract characteristic parameters of swelling behavior. The study was performed for different shales with appreciable variation in smectite, illite and Cation Exchange Capacity (CEC). Swelling of these shales in WBM was investigated using different salt concentrations, mud weights and viscosities of the fluids.Shale swelling as a function of time was modeled in a novel way as %S(t) = A*[f(B*t)+C*g(t)] where %S(t) represents swelling at time t. The equation was derived after combining first order kinetics term as f(B*t) with filtration loss term based as C*g(t). Thus, A represents saturation swelling volume, B represents first-order rate of swelling and C is filtrate loss rate parameter. The model fits well to experimental data with R 2 > 0.97 for all shale-fluid combinations investigated which was used to extract the characteristic parameters.Saturation swelling volume, A, increased with an increase in CEC of the shale. In addition, A decreased linearly till a critical salt concentration in fluid was reached and then flattened out with further increase in salt concentration. Such behavior conforms to osmotic transport of water through shale. It was observed that A was independent of mud weight and fluid viscosity; however B was observed to increase with a decrease in viscosity which may be interpreted as result of diffusion phenomena governing swelling rate. Filtrate loss rate parameter C was estimated to be between 0 and 1 in most of shale-fluid combinations studied. Information obtained from parameters A, B and C can allow us to optimize WBM formulations for shale that can save cost and time. IntroductionTo predict and manage borehole instabilities during drilling, it is important to have a detailed understanding of the effects that a drilling fluid may have on the shale behavior.In the drilling industry, several experimental tests and numerical models have been developed by researchers to describe the interaction between drilling fluids (specifically, water-based muds) and shale. Various experimental devices were demonstrated by Chenevert (1989) that could be used to measure the swelling of shales as they come in contact with waterbased muds. Horsrud (1998) investigated the effect of potassium chloride (KCl) exposure on smectite-rich shales by various experimental techniques, under both atmospheric and simulated downhole conditions. On the computational side, Molenaar (1998) developed constitutive models to describe fundamental understanding of the interaction between the drilling fluid composition and the mechanical behaviour of shale swelling based on transport equations for the fluids and the ions. Huang (1998) probed the effect of physio-chemical shale-fluid interaction on shale...

Managing shale swelling is critical when drilling with water-based muds (WBMs). Excessive swelling can lead to shale sloughing, borehole collapse, stuck pipe, and shale disintegration. The fine solids content can increase and cause difficulties controlling rheological properties. Linear swell meter (LSM) testing is a well-known laboratory procedure used to characterize shale swelling in a WBMs.A mathematical modeling tool known as the artificial neural network (ANN) was used to model shale swelling in a WBM. The ANN model establishes complex relationships between a set of inputs and an output based on computational modeling. For ANN modeling of the shale-swelling, the shale mineralogy and fluid composition constituted input parameters, while the output was represented by an experimental characteristic swelling parameter derived from the "% swelling vs. time" data from the LSM test for the respective shale-fluid combinations.Experimental data for building the ANN model was obtained by performing about 250 standard LSM tests on different shales with varying mineralogy and WBMs with varying salt concentrations. This shale swelling ANN model provided excellent correlation with R 2 > 0.9. The ANN model was then successfully validated for an independent set of shale-fluid conditions.Using the shale swelling ANN model, shale-swelling in WBM was predicted for a given shale mineralogy and fluid composition. This reduced the number of trials necessary to determine an optimized WBM formulation. Mud engineers can use this model in real-time as the shale chemistry varies with the depth of the formation drilled. The model provides a helpful measure of fluid performance to determine the optimization necessary to obtain the desired shale behavior. Using this method can help minimize drilling risks and costs associated with unpredictable shales. IntroductionUnderstanding the shale response in the presence of a drilling fluid is crucial to predict and manage borehole instabilities during drilling. Within the drilling industry, researchers have developed several experimental tests and numerical models to describe the interaction between shale and a drilling fluid (specifically, a WBM).Related to experiments, Chenevert and Osisanya (1989) provided various devices that can be used to measure swelling response of shales as they come in contact with WBMs. The effect of potassium chloride (KCl) containing fluids on smectiterich shales was investigated by Horsrud et al. (1998), under both atmospheric and simulated downhole conditions.With respect to computation, Molenaar et al. (1998) described the interaction between the drilling fluid composition and the mechanical behavior of shale based on constitutive models consisting of transport equations for the fluids and the ions. The effect of physio-chemical shale-fluid interaction on shale formation pressure and shale swelling was studied by Huang et al. (1998) using numerical simulations and modeling. In work closely related to this paper, Basma et al. (2003) attempted to implement sequent...

Barite sag and poor hole cleaning are not problems; they are symptoms of well control and stuck pipe problems. Issues with barite sag and hole cleaning are routinely encountered while drilling high pressure high temperature (HPHT) wells. Maintaining optimal mud rheology in HTHP conditions (350°F+) can be very difficult. Adding organo-clays or low gravity solids (LGS) to boost rheology can lead to high equivalent circulating densities (ECD) and low rates of penetration (ROP).The new HPHT organic rheology modifier (ORM) imparts optimal rheological properties to low, medium and high density clay-free invert emulsion fluids (IEF). Clay-free systems have previously demonstrated superior gel strength and rheological profiles over conventional organo-clay and lignite treated fluids. Although significant improvement in these systems seemed unlikely, this was accomplished with the new ORM chemistry.These IEFs exhibit enhanced low shear rheology (even at 9.0 ppg) with lower or similar plastic viscosity (PV) values when compared to IEFs formulated without the new HPHT rheology modifier. When tested at up to 400°F and 18,000 psi, the IEFs formulated with ORM show similar or higher low shear rheology with low PV than under ambient condition. A good low shear rheology implies better hole cleaning and sag control. A low PV improves ECD control.Treatment with ORM imparts fragile gel characteristics to 9.0 to 18.0 ppg clay-free IEFs. The rapid gel-to-flow transition helps to minimize surge and swab pressures and reduce mud losses. The new HPHT rheology modifier with a biodegradability of 67% in 28 days also stabilizes the IEF and provides comparatively low fluid loss values. It also eliminates the need to add LGS to boost rheology. The paper presents experimental data demonstrating both the environmental and rheological performance of the HTHP rheology modifier as well as comparative data from the conventional clay-free fluids without the ORM.

Historically, shale instability is a challenging issue when drilling reactive formations using water-based muds (WBM). Shale instability leads to shale sloughing, stuck pipe, and shale disintegration causing an increase in fines that affects the rate of penetration. To characterize shale instability, laboratory tests including Linear Swell Meter (LSM), shale-erosion and slake-durability are conducted in industry. These laboratory tests, under different flow conditions, provide shale-fluid interaction parameters which are indicative of shale instability. The composition of WBM is designed to optimize these interaction parameters, so that when used in the field the fluid helps achieve efficient drilling. This paper demonstrates modeling of shale-fluid interaction parameters obtained from the LSM test. In the standard LSM test, a laterally confined cylindrical shale sample is exposed to WBM at a specific temperature and its axial swelling is measured with time. The swelling reaches a plateau which is characterized by a shale-fluid interaction parameter called % final swelling volume (A). A typical LSM test runs for around 48–72 hours and many tests may be needed to optimize fluid composition. In this work, a method/model is developed to predict final swelling volume (A) as a function of the Cation exchange capacity (CEC) of the shale and salt concentration in the fluid (prominent factors affecting shale swelling). An empirical model in the form of A = f(CEC)*f(salt) which describes the explicit dependence on the influencing variables is developed and validated for 16 different shale samples at various salt concentrations. This model would significantly reduce LSM laboratory trials saving time and money. It could also enable rig personnel to obtain quick measure of shale characteristics so that WBM composition could be adjusted immediately to avoid shale instability issues.

Lost-circulation materials (LCMs) are often used to mitigate the loss of drilling fluids into subterranean formations. Well-known LCMs include ground marble, graphitic carbon, and cellulosic particulates. The carrier fluid's ability to suspend the LCM material is critical in high-pressure/high-temperature (HP/HT) or inclined wells. This paper provides methods to help determine and manage suspension characteristics of LCMs in the fluid with the aid of certain suspending agents (e.g., fibers).A detailed experimental study was conducted to evaluate the suspension of a range of LCMs in various drilling fluids and investigate the effects of suspending agents (e.g., fibers) on LCM suspension. Based on experimental data, semiempirical models were developed to help predict the influence of fibers on LCM suspension. The design parameters used in these models included fiber concentration, fiber density, number of fibers per unit volume, and average fiber length and diameter. The modeling work discussed in this paper also provides methods for tailoring the suspending agent properties necessary for achieving effective LCM suspension in the fluid.The uniform suspension of LCM in the carrier treatment or drilling fluid is necessary during LCM pill preparation and during wellbore applications, such as a hesitation squeeze operation. Thus, using fibers to manage the suspension characteristics of LCM in carrier fluids can help ensure efficient use of LCMs for lost-circulation control. This method is particularly important in severe-loss zones where large sized LCMs are used as well as in HP/HT or inclined wells where maintaining LCM in suspension can be challenging.