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Mud-gas technologies for continuous PVT-like analysis of reservoir fluids in the drilling mud require a calibration procedure to determine the efficiency of the gas extraction process. This procedure is required because the efficiency of the hydrocarbons extraction process is strongly affected by the drilling mud type and properties, and so it must be performed any time the mud significantly changes.

The calibration procedure requires a sample of drilling mud that contains significant amounts of alkanes. Currently, this sample is collected while drilling during a gas peak and stored until the end of the phase, when the calibration can be performed. Thus, the gas extraction efficiency can only be determined at the end of each drilled section, and the quantitative analysis of the reservoir fluid in the mud is made available only at the end of each section.

This paper presents a new procedure, in which a Calibration Mud sample is built by injecting and emulsifying several alkanes into the mud. The calibration can then be performed at any time before drilling commences.

It is extremely difficult to inject and dissolve gaseous light hydrocarbons into a mud sample at the rigsite. For this reason, we inject a sample of six liquid alkanes into the mud and emulsify it to build a mud sample suitable for the calibration procedure. The extraction efficiencies for the lighter gas alkanes are then extrapolated from those of the injected alkanes using a model of the extraction process.

The new calibration process has been tested in several wells around the world. In each test, the new calibration process and standard calibration (performed at the end of the phase using mud collected while drilling) were performed. Validation of the new technique comes from ensuring the extraction efficiency coefficients using our new calibration mud match those coming from the standard calibration. The results were conclusive with similar coefficients obtained in each test. The uncertainty intervals overlap, and the calibration coefficients are statistically equivalent.

The new calibration procedure represents an innovative methodology enabling real-time, continuous quantification of the light hydrocarbons content (C₁-C₆) of the reservoir fluid, comparable to the PVT monophasic composition, while drilling, at surface. This is the first time that such data can be delivered in real-time while drilling. The resulting measurements have multiple applications such as enhanced geosteering and well placement, real-time identification of gas-oil contacts, and real-time selection of sampling points and can be integrated with downhole tool measurements to provide a true real-time understanding of the subsurface fluids.

The StressCage methodology of wellbore strengthening uses sized particles to bridge and seal induced fractures, increasing fracture resistance in permeable formations. The size distribution of the particles, or fracture prevention material (FPM), that are added to the mud is engineered to ensure correctly sized particles enter and bridge the induced fracture before it grows beyond its designed width and length. A minimum concentration of FPM is determined through a physics-based numerical calculation to derive a mud formulation based on the particle size distribution (PSD) and density of the selected mud additives. This minimum concentration and particle size distribution of FPM must be maintained at all times that the wellbore pressure exceeds the fracture gradient or previously generated fracture resistance of the formation in order to prevent the failure of the StressCage and the subsequent loss of wellbore integrity.

A number of methods have been used to monitor FPM concentration in the mud. Most methods sample the mud returning from the well before arriving at the mud shakers, pass the collected mud sample through stacked sieves, remove the liquid mud coating the particulates using either centrifuges or drying ovens, and weigh the resulting residue to determine the return concentration. These methods can be inadequate and difficult to implement due to the requirement of specialized equipment on the rig (ovens, laser PSD, centrifuges, etc.), the need for additional personnel to conduct the mud monitoring activities on the rig, and the significant delay in obtaining the results. The lag time for results in deepwater wells can be 5 to 10 hours, depending on the time required to circulate the mud up the well and dry the samples. This delay can prevent operators from detecting when FPM concentration decreases to below the minimum required for drilling depleted sands.

A simple and fast method has been developed that requires minimal special equipment. A reference sample is collected from a reserve mud pit carefully prepared with the target minimum FPM concentration. The mud is then run though a set of selected stacked sieves. The reference tare weights of the wet FPM collected in each sieve are used as a reference for monitoring the active system. The reference wet FPM weight is compared to mud samples collected from the suction pit of the active system as the well progresses. The difference in the weight observations is then used to determine appropriate additions to maintain or exceed the minimum requirements.

Fluid-shale compatibility testing is as old as the drilling fluid industry itself, and remains a highly relevant topic as drilling applications explore new, more complex territory. Incompatibilities of fluids with clay-rich shale formations can lead to a plethora of operational problems, ranging from minor dispersion and accretion issues to major stuck pipe and production impairment events. The nature of fluid-shale interactions has confounded scientists since the birth of the drilling fluid industry, and has led to a variety of different test methods and protocols, many now decades old. The question remains: what are the best, most representative fluid-shale compatibility tests to characterize fluid-shale interactions and avoid making costly mistakes based on misleading test results?

Historical fluid-shale compatibility tests are often severely limited by over-emphasizing the role of clay swelling behavior, by not paying attention to shale sample condition, and by not being specific with regard to the intended purpose. Test selection is often based on a superficial assessment of the "reactivity" of the shale, and results are indiscriminately applied whether the intended purpose is maintaining cuttings integrity, promoting borehole stability or avoiding reservoir incompatibility to name a few. This paper points out the various pitfalls and problems associated with conventional tests such as atmospheric swelling tests and capillary suction time tests, which still find wide-scale application in the oil and gas industry. A case is made to abandon such tests in future. New sets of tests are proposed that may overcome the drawbacks of the conventional tests. These tests are also conducted with a clear purpose in mind. For instance, to evaluate borehole stability, it is argued to forego traditional swelling tests and instead focus on triaxial failure testing, mud pressure transmission testing and borehole collapse testing. The latter can be accomplished with a novel, low-cost alternative to the downhole simulation cell test in the form of a modified thick walled cylinder test. This new test exposes cylindrical shale samples, confined under downhole temperature and pressure, to mud formulations at overbalance for a specified period of time and assesses the failure strength of the sample thereafter.

Recommendations for shale characterization and to investigate fluid shale interactions relevant to shale cuttings integrity, borehole stability and reservoir compatibility for conventional and unconventional reservoirs are given here. The tests are illustrated with representative results obtained for novel mud systems such as high-salinity fluids and muds containing nano-particles. Recommendations with respect to applying laboratory results to field operations are provided.

Wellbore stability in shale is often hampered by the detrimental effect of existing weak bedding planes on the strength of the rock surrounding the wellbore against shear failure. This paper presents results from a formal closed-form analytical solution to the wellbore stress problem that incorporates rock failure along weak bedding planes. The solution is used for a case study of a highly inclined well section in a laminated layer of troublesome shale with a strike-slip faulting regime above the target formation in the Latin America region.

The BP project team has considered increased reserves recovery by lowering the reservoir abandonment pressure below the initial design value. Through a multi-disciplinary approach, design assumptions and equipment ratings were systematically reviewed to determine which aspects factored into the decision to change reservoir management. Collapse loading of the 10 in. production liner was identified as a key variable.

The conventional design factor, a ratio of the design load to the API collapse rating, was deemed to be an insufficient way of characterizing design margin, primarily due to the perception of conservatism in the rating. While design factors are convenient for screening a casing string against an agreed-upon set of inputs and assumptions, there is little insight gained from comparing a 1.03 design factor to a 1.02 other than one value is higher than the other. The team embarked on a scope of work to characterize the probability of collapse as a function of reservoir abandonment pressure using reliability based design (RBD).

Physical testing was conducted to characterize the distribution of collapse resistance and the distribution of dimensional and strength parameters which govern collapse. The quality data sets are combined using the Klever-Tamano limit state equation to indirectly derive a distribution of collapse resistance. The destructive collapse tests provide both a direct measure of the distribution of collapse and a way to calibrate the limit state equation model uncertainty. Both the direct and indirect methods are useful in determining the probability of collapse for a design load.

Load uncertainty was characterized by considering variability of conditions across the wellstock, including depth, temperature and completion configuration. Casing wear was also considered in the assessment.

This paper outlines the RBD methodology used to support the decision to lower reservoir abandonment pressures. Details on how to construct the statistical collapse model are provided along with a discussion on interpretation and continuous improvement activities.

There are many causes for injection wells to perform poorly; in this paper, we address the effect of residual hydrocarbons near the wellbore, which reduce the rock's effective permeability to brine, thus decreasing well injectivity. Immobile hydrocarbon saturations are found around injection wells when these are drilled above the water-oil contact level, which arises when a producer well is switched to injection, or the formation's underlying aquifer is hard to reach. Furthermore, oil can accumulate around a wellbore when produced brine containing even trace amounts of hydrocarbons is used as the injection fluid. To address this problem, it is possible to flush out hydrocarbons around the wellbore by periodically injecting small amounts of surfactants for short periods. This technique leverages the capillary desaturation behavior of a multi-phase fluid mixture, wherein increasing the capillary number of a rock-fluids system beyond a threshold value will decrease the residual hydrocarbon saturation. The capillary number, which characterizes the ratio of viscous to capillary forces, can be increased by injecting surfactant loaded brine; this reduces the hydrocarbon-brine interfacial tension which reduces the capillary forces, decreases the system's residual hydrocarbon saturation, and increases the brine's effective permeability. To efficiently assess the impact of a surfactant flush, we perform digital rock multi-phase flow simulations on Berea and Fontainebleau sandstones at different capillary numbers. The simulations provide the residual hydrocarbon saturation and the brine's effective permeability as a function of capillary number, which is related to the amount and type of surfactant. These results are then used in a radial wellbore simulation to compute the attainable injection rate for a maximum allowable pressure drop. Since the largest pressure drop occurs very close to the wellbore, the surfactant flush is very effective even though it only affects a few feet from the wellbore. For the specified scenario we observe a potential well performance improvement ranging between 20% and 150%. By using digital methods, this study was performed in about two weeks, at lower cost than Special Core Analysis Laboratory (SCAL) physical testing, and with ideal reproducibilty since the capillary number can be modified without affecting the sample or any other aspect of the test procedure.

Many shale and limestone formations exhibit natural fractures in the form of calcite veins. Although these natural fractures might be sealed, they are prone to activation in hydraulic fracturing operation due to their low mechanical properties. Once these fracture are activated, the flow in such fractures without proppants play a role not only in production performance but also in analyzing the mechanisms responsible for the low recovery of water flowback. To address this issue, we created induced fractures within calcite veins of Niobrara formation using indirect tensile experiment and fracture permeability experiments were conducted by injecting both water and gas. The results of fracture permeability tests in Niobrara formation were compared with the results of fracture permeability tests in granite sample. The effective fracture permeability to water is significantly lower than the fracture permeability to gas in calcite veins while the fracture permeability of granite sample to both water and gas is almost similar. Comparing the fracture permeability of the Niobrara sample with the granite sample provides some insights into the possibility of water trapping microfractures as a possible reason for low water-flowback recovery. Besides the interaction of water with rock, fracture roughness can be another mechanism affecting fracture permeability. To this end, the topographic surface of samples were measured by laser profilometer and the fluid flow in rough fractures were simulated numerically to analyze the effect of roughness on fracture permeability.

In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation are integrated to quantify the changes in the effective water permeability, capillary pressure and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated.

The researchers considered a spontaneous imbibition of a 0.1 wt% friction reducer fluid into low-permeability sand core samples extracted from Scioto, Crab Orchard, and Kentucky outcrops. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using distilled water, friction reducer fluid, and distilled water again. Prior to each experiment, the core sample was cleaned with toluene and then dried completely. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus.

The results showed that the polymer adsorption throughout the fracturing fluid spontaneous imbibition significantly reduces the water spontaneous imbibition volumes. Moreover, the polymer adsorption effect increases as the porosity increases. The results showed also that the effective water permeability is decreased because of the the polymer adsorption effect. The Residual Resistance Factors calculated from the spontaneous imbibition experiments are in agreement with the values calculated from the constant rate permeability measurements.

Adding surfactant to the pad stage- friction reducer fluid increases its spontaneously imbibed (leak-off) volumes. The results showed also that the effect of polymer adsorption on the imbibition rates is significantly less when the rock-fluid contact surface is parallel to the bedding plane.

The imbibition potentials were calculated before and after polymer adsorption. Since the water permeability was calculated independently, the capillary pressure curves were calculated from the imbibition potentials. The results showed polymer adsorption leads to a slight increase in the capillary pressure. The spontaneous imbibition experiment is numerically simulated using ECLIPSE commercial simulator and the imbibition water relative permeability curves were calculated by matching the results to the water spontaneous imbibition experimental data. The results showed that the polymer adsorption significantly reduces the water relative permeability curves for Scioto and Crab Orchard.

The integrity of a well is a crucial component for the longevity of a well. Cement isolates the casing and protects the well from fluids, pressure, and other components that may jeopardize its stability. Extreme care and research should be invested in analyzing the water quality that is used to mix cement. In this study, the effects of water quality on API Class G-Portland cement were studied to understand the relationship between water quality, rheology, thickening time, and compressive strength. Although extensive research has been made on well cement in general, no previous research focused on oilwell cement water quality was available until now. Thus, this paper is intended to serve as reference as well as motivation for future research. Cement thickening time was recorded using a cement consistometer and compressive strength using a universal testing machine. We tested several samples including soft to very hard, very saline and field waters. We also tested the hard water at different temperatures to investigate the effect of temperature on thickening time. A positive correlation occurred between the temperature of the mixing water and consistency, the higher the temperature was of the mixing water, the faster the consistency rose. In contrast, a negative correlation between water hardness and thickening time occurred. As water hardness increased, thickening time decreased and vice versa. A percentage change up to 2.4% was recorded between different water qualities making soft water (0 gm/L) have a longer thickening time in comparison to very hard water (180 gm/L+). Variations on the pH of the different waters used did not seem to have a significant impact on the results obtained. Compressive strength results showed that soft water (water with no hardness) is the strongest among the other samples prepared with different waters. In addition, a similar trend cannot be observed at different curing times. For instance, some samples show high strength on the first day but drops as cement hydration time increases.