As we approach an age of deeper discoveries in hostile environments, we need to either improve on existing drilling fluids or design new ones in order to meet the technological demands for success. The filtrate invasion is the most critical parameter that may cause a wellbore failure if not properly controlled. Also, the filtrate induced formation damage and problems with filter cake removal adversely affect the well productivity or injectivity.The literature survey reveals the advantages of polymer, surfactant and Nanoparticles systems independently and also combination of two of these. A study is necessary to see the effect and advantages of combining all three systems together i.e. a Polymer-Surfactant-Nanoparticles system and to measure the rheological and fluid loss characteristics of the complex combined drilling fluid system. An attempt to study the same has been made in paper. Therefore, in this paper the authors present the results of testing the rheological properties and the API filtrate loss of a Bio-Polymer and Surfactant blend system with addition of Nanoparticles and compare the fluid loss reduction by using Nanoparticles as fluid loss additive with an industry standard polymer-based fluid loss additiveThe objective of this research was to study the effectiveness of a Bio Polymer -Surfactant fluid blends, containing Nanoparticles as fluid loss additives in reducing the filtrate losses to the formation by forming a thin, non-erodible filter cake.Laboratory experiments were carried out for the different combination of polymer and surfactant with varying concentrations to find the optimum of fluid performance. The laboratory measurements included measuring mud weight, pH, viscosity, gel strength, standard API filter test and High Temperature High Pressure (HTHP) test using Permeability Plugging Apparatus.Presented results show that sized silica nanoparticles can be used instead of sized calcium carbonates which are a very effective inorganic bridging agent, however, difficult to maintain. The polymer -surfactant blend is better in rheological properties as well fluid loss properties than a Bio-Polymer based fluid or Surfactant based fluid. It captures the merits of both fluid systems. The nanoparticles play an important role in reducing the fluid loss of the individual fluid systems. Also, the nanoparticles based Polymer-Surfactant blend is a good solution for solids free reservoir drill in fluids for horizontal shale drilling applications. The nanoparticles is most effective for shale drilling application as it can penetrate the pores of the shale and act as a bridging material and causing wellbore strengthening.

Shale has been known to be the source of wellbore instability during the drilling process. Organic rich shales are anisotropic due to their laminated structure and chemical properties. The goal of this study is to evaluate anisotropic mechanical properties of shale by triaxial tests, and predict shale anisotropic properties by well logging data interpretation. Shale samples were prepared with bedding plane inclination angles equal to 0 degrees, 45 degrees, and 90 degrees. Young's modulus, shear modulus, and Poisson's ratio in different directions were measured for a sample with 0 degrees bedding plane inclination angle. Parameters of the stiffness tensor were calculated by mechanical properties. Compressive strength was measured under different confining pressures of 0 psi, 500 psi, 1000 psi, and 1500 psi. The strength properties of shale samples were evaluated by both compressive strength and tensile strength. Simple Plane of Weakness and Modified Cam Clay failure criteria were applied to describe shear failure mechanisms. A scanning electron microscope method was used for the comparison of micro structures between the intact shale sample and failed sample with different bedding plane inclination angles. Well logging data was used to connect experimental lab data and field data. Compressional wave velocity was predicted with different inclination angles by stiffness parameters. The predicted compressional wave velocity for a 45-degree inclination angle showed a perfect fit with the field logging data. Steps of inverse sonic log data to stiffness parameters were shown by a flow chart. The UCS strength for 0 degrees and 45 degrees was predicted by several empirical relations using sonic logging data. The safe mud window for this special shale formation is predicted by experimental data. As shown in experimental results, our shale sample has a weak direction for both failure criteria. Well logging data and experimental data can be connected, especially by sonic log data. However, to predict shale anisotropic strength through well logging still requires more effort. The novelty of the process which connects experimental results and well logging data will be helpful for solving instability problems occurring in shale formation.

With several limiting assumptions, a mathematical model of the diamond-bit drilling, process has been developed. The model represented by an instantaneous rate-of-penetration equation takes into account the reduction in penetration rate during drilling resulting from bit wear. The model has been tested both under laboratory and under field conditions. The comparison of the theoretical and experimental results has shown reasonable agreement. A method for estimating rock properties also has been established. Using this method, we can find the so-called index of rock strength and the index of rock abrasiveness. Introduction Several published studies concerned with diamond-bit drilling report on rock properties and drillability. drilling fluid additives, diamond wear, and drilling performance theories. Among the factors, that affect diamond-bit drilling performance, the type of formation to be drilled is of utmost importance since it significantly affects the type of bit, the drilling practices. and subsequently the rate of penetration and the drilling cost. The nature of the formation is also one of the main factors in planning deep wells, fracture jobs, mud and cement technologies, etc. For rock properties evaluation as well as for selection of proper drilling practices, several descriptions of the diamond-bit drilling process have been developed. The relevant literature is extensive and is not reviewed in this paper. The objective of this paper is to describe the diamondbit drilling model for surface-set diamond core bits and its application to determining the index of formation strength and the index of formation abrasiveness. The main difference between our model and the models known in literature is that we consider the effect of friction between the diamond cutting surfaces and the rock. A decrease in penetration rate is observed if the drilling parameters, are constant and if the formation is macroscopohomogeneous. Drilling Model The drilling model for a surface-set diamond core bit is subjected to the following limiting assumptions.Rock behavior during cutting with a single diamond may be approximated by a rigid Coulomb plastic material.The active surface of the bit is flat, and diamonds are spherical with diameter. d.The cross-sectional area of the chip formed by a single diamond is equal to the diamond cutting surface and can be established by geometry.During drilling, the neighboring diamonds work together to make a uniform depth of cut (Fig. 1).A number of diamonds forming one equivalent blade have to provide it uniform depth of cut from the inner to the outer diameter of the diamond core bit. so the bit is modeled to be a combination of several equivalent blades (Fig. 2).The diamond distribution technique provides uniform radial coverage that results in equally loaded cutting diamonds.Individual cutting diamonds perform some work that results from the friction between the rock and the diamond.Bit wear is assumed to be gradual while drilling is in progress. Under the preceding assumptions we may state that the drilling rate of the surface-set diamond core bit is a function only of weight on bit (WOB), rotary speed, average density of the diamonds on the bit's active surface, diamond size, core-bit diameters, rock properties, and degree of diamond dullness. The effects of flow rate, differential pressure, hydraulic lift, drilling fluid properties. and drillstring dynamics are ignored. According to Peterson, the penetration rate of the diamond bit, after some modifications, can be described by the following simplified equation. (1) This equation does not include the effect of diamond wear and hence pertains to unworn bits or to when bit dullness is negligible. SPEJ P. 911^

In the industry as a whole, we are still at the beginning of the learning curve for shale oil drilling operations; however, many shale-oil wells have been drilled in recent years. Drilling through shale-oil formations is very problematic and imposes significant costs to the operators owing to wellbore-stability problems. These problems include, but are not limited to, tight holes, stuck pipe, fishing, sidetracking, and well abandonment. To more efficiently and effectively drill through these formations, we should better understand their properties.Few experiments have been performed on shale-oil samples to better understand their properties. Most experiments conducted thus far were performed on common shale core samples, which are significantly different from shale oil samples. In this study, we first determined the mineralogy of shale-oil core samples from the Eagle Ford field and then investigated the swelling properties and Cation Exchange Capacity (CEC) of the core samples in the laboratory. Experiments have been conducted with the samples partially submerged in distilled water and potassium-chloride (KCl) brine. Several experiments have been performed using strain gages to measure lateral, axial, and diagonal swelling in both submerged and nonsubmerged areas.The results demonstrate that the swelling properties and CEC of the shale oil core samples are different from the common shale core samples. This study proposes the quantification of the shale/fluid properties, the interaction, and the effects of different fluids on rock properties in unconventional reservoirs. This paper presents and documents the differences in the swelling properties between conventional and unconventional shale. The results of the study will help us to more precisely understand unconventional shale oil rock properties and can be used to design a more effective drilling fluid for field applications, as well as more accurately predict the mechanisms of formation failure.

Most real-time drilling interpretation is performed using some sort of normalized rate of penetration to infer changes in lithology and evaluate the condition of the bit. This frequently leads to ambiguous or confusing results, because it is impossible to separate all bit effects from lithology effects using only one measurement. Also, no method exists to evaluate drill bit performance such as directional responsiveness and steerability. This paper proposes a new model of bit performance evaluation and shows how the force and moment measurements can be used to separate the bit effects from the lithology effects when drilling with PDC bits. Analytical results of rock/bit interaction modeling are based on the laboratory drilling force measurements during rock comminution with a PDC cutter. It was found that a given rock/PD C system results in the specific relationship between axial and tangential drilling forces. This empirical relationship is used to determine the distribution of drilling forces and moments on a generic conventional PDC bit. Then, it is shown how the measurements of force and moment generated during drilling can be used in bit wear and lithlogy changes evaluations. This model accounts for abrasive wear of the cutters and detects those that are exposed to more severe loads. Thus, it may be also used as a guide in bit selection and bit design modifications. If verified in the harsh economic environment of today, field application of the method should lead to a better understanding of downhole conditions and a more accurate decision as to what direction a bit is drilling, when to pull out bits, and thus to a reduction of drilling costs. P. 185