Abstract Friction reducer evaluations for field application selection are conducted in laboratory benchtop recirculating flow loops or once-through systems. Industry standard procedures and benchtop flow loop (loop) system specifications for friction reduction assessment are nonexistent, though standardization efforts are recently documented. Research and papers correlating friction reducer performance to brine and additives have been published, however other key variables can significantly affect performance and therefore must be addressed to maximize product recommendation accuracy. This paper illustrates how variances affect results. Benchtop recirculating loops used for testing friction reduction products for a specific field's application vary significantly in system components, configurations, and test analyses. Crucial loop system variance examples include differing pipe diameters, pump configurations, flow meter types and placement, differential pressure section and full run lengths, reservoir designs, mixing conditions, and end performance calculations. Oil and gas producers and service companies are trending towards outsourcing friction reducers to independent testing laboratories for loop assessment results prior to recommending friction reducers for end use field applications. These recommendations may have inherent selection bias depending upon the loop system's components and configuration. Friction reduction calculations during loop testing do not consistently consider changes in viscosity and temperature, thereby altering absolute results when evaluating performance. To apply the simplified assumptions in standard pressure, drop methodology, equivalency in flow rate, density, viscosity, and temperature within the run must be maintained. Performance of the friction reducer in a specific brine and additive test run should primarily be dependent upon dosage and method of injecting friction reducer into the loop, however other variables can contribute to performance results. We presume equivalency in pipe roughness and proper loop cleansing. The effects of these variables on friction reduction response applying wide-ranging factors of flowrate, density, viscosity, and temperature are evaluated using designed experiments with responses plotted and illustrated in Cartesian and contour graphs. The result of these designed experiments identified that certain variables are more influential on friction reducers’ measured performances in standard loop experiments and require observation and documentation during performance testing. The final study in this work generated vastly different performance curves when all of the aspects of loop design, entry and differential run lengths, flow rate, injection method, friction reducer types and loadings, and brine types, densities, viscosities, and temperatures were held constant. The goal of benchtop loop testing is scaling for actual field applications. Scaling discrepancies persist however due to differing pipe diameters, fluid circuit designs, and pump types and rates combined with changing brine compositions, proppant, and chemical additive effects on friction reducer products. Understanding that different benchtop loops, or potentially the same benchtop loop, will generate differing results is intriguing, yet unsettling.

Abstract Calcite, as one of the most common scales in oilfield can be inhibited by common scale inhibitors. The measurement of calcite nucleation and inhibition is a challenge, because of the difficulty to control pH as a result of CO2 partitioning in and out of the aqueous phase. A new kinetic turbidity test method was developed so that the partial pressure of CO2, pH, and SI can be precisely controlled. Calcite nucleation and inhibition batch tests were conducted under various conditions (SI = 0.24-2.41, T = 4-175 °C, and pH = 5.5-7.5) in the presence of common phosphonate and polymeric inhibitors. Based on experimental results, calcite nucleation and inhibition semi-empirical models are proposed, and the logarithm of the predicted induction time is in good agreement with the measured induction time. The models are also validated with laboratory and field observations. Furthermore, a new BCC CSTR Inhibition (BCIn) test method that applied the Continuous Stirred Tank Reactor (CSTR) theory has been developed, for the first time. This BCIn method was used for calcite inhibitor screening tests and minimum inhibitor concentration (MIC) estimation. By only running one experiment (< 1 hour) for each inhibitor, BCIn method selected the effective inhibitors among 18 common inhibitors under the conditions of SI = 1.23 at 90 °C and pH = 6. It was also found that the critical concentration (Ccrit) from BCIn method has a correlation with the MIC from batch tests. This study provided a simple and reliable solution for conducting calcite scale inhibition tests in an efficient and low-cost way. Furthermore, the newly developed prediction models can be used as guidance for laboratory tests and field applications, potentially saving enormous amounts of time and money.

Abstract Despite attempts to inhibit or avoid the formation of fouling deposits (polymeric amorphous dithiazine or apDTZ for short) from the use of MEA triazine, this remains a major operational problem and limits the use of this most popular and ubiquitous hydrogen sulphide (H2S) scavenger. This paper (a) reviews and summarizes previous work, (b) provides fresh insights into the reaction product and mechanism of formation, (c) proposes an effective method of removal, and (d) proposes some mechanisms of apDTZ digestion. The mechanism of apDTZ formation is discussed and reasoning is provided from a variety of perspectives as to the mechanism of MEA-triazine reaction with H2S. These include basicity and nucleophilic substitution considerations, steric properties and theoretical calculations for electron density. Novel procedures to chemically react with and destroy this solid fouling are presented with an in-depth study and experimental verification of the underlying chemistry of this digestion process. A review of agents to chemically destroy apDTZ is undertaken and a very effective solution has been found in peroxyacetic acid, which is much more powerful and effective than previously suggested peroxides. The structure of amorphous polymeric dithiazine is emphasized and the reason why this fouling cannot be 1,3,5-trithiane is stressed. This work therefore overcomes a current industry misconception by providing insight on two major paradoxes in the reaction pathway; namely i) why the thiadiazine reaction product from tris hydroxyethyl triazine (MEA triazine) is never observed and ii) why does the dithiazine in all cases never progress to the trithiane (3 sulphur molecule substitution)? The latter issue is probably the biggest misconception in the industry and literature regarding triazine and H2S reactions. Many reasons for this are put forward and the common misconception of "overspent" triazine is refuted. A very effective chemical reaction that results in soluble by-products, counteracting the problems produced by this intractable polymer is found and their composition is proposed and experimentally verified.

Abstract Halite scaling has been observed in the oil/gas field with high TDS and low water cut. Due to its higher solubility, slight changes in temperature (T) and pressure (P) and evaporative effect could yield a large amount of scale, causing significant operational problems. Accurate prediction and control of halite scaling in the oil and gas production system have been a challenge. Therefore, this study aims to shed light on the prediction of halite scale formation, deposition behavior, and inhibition at close to oil field conditions. We have designed and developed a dynamic scale loop (DSL) test methodology that can be used at various T and P. The test method utilizes a change in temperature (ΔT) as a driving force to create halite supersaturation and follow with the scale precipitation/deposition. The tube blocking experiments suggest that the tube blockage can be caused by bulk precipitation and or deposition of halite precipitate. SEM analysis of the tube cross-sections indicated that tube blockage, presumably by bulk precipitation, could be seen at the beginning of the reaction tube, but deposition was observed towards the exit end of the tube. Similarly, various experimentation to simulate the water dilution at constant pressure and ΔT were conducted. The effect of the addition of water to prevent halite deposition was analyzed computationally by using ScaleSoftPitzer (SSP) software. Brine compatibility of several inhibitors were tested via bottle tests and autoclave tests and qualified inhibitors were tested in the tube blocking experiments to identify the performance of the inhibitor to treat the halite precipitation at high temperature and pressure. Overall, a robust test method was designed and developed for halite scaling under high temperature and pressure that can simulate the oil and gas production in the field.

Abstract Preservative biocides are designed to control microbial growth and biogenic souring in the downhole environment. We report the prevention of biogenic souring by 4,4-dimethyloxazolidine (DMO, a preservative biocide) and glutaraldehyde as compared to that afforded by tributyl tetradecyl phosphonium chloride (TTPC, a cationic surface-active biocide), in a first-of-its kind suite of High Pressure, High Temperature (HPHT) Bioreactors that simulate hydraulically fractured shale reservoirs. The design of these new bioreactors, which recreate the downhole environment (temperatures, pressures, formation solids, and frac additives) in a controlled laboratory environment, enables the evaluation of biocides under field-relevant conditions. The bioreactors receiving either no biocide treatment or treatment with a high concentration of TTPC (50 ppm active ingredient) rapidly soured within the first two weeks of shut-in, and all surpassed the maximum detectable level of H2S (343 ppm) after the addition of live microbes to the reactors. Conversely, a higher loading of DMO (150 pppm active ingredient) maintained H2S concentrations below the minimum dectable level (5 ppm) for six weeks, and held H2S concentrations to 10.3 +/- 5.2 ppm after fifteen weeks of shut-in and two post shut-in microbial rechallenges. In a second study, a lower concentration of DMO (50 ppm active ingredient) maintained H2S concentrations below the minimum detectable level through the addition of live microbes after three weeks, and H2S concentrations only registered above 10 ppm upon a second addition of live microbes after five weeks. In this same study (which was performed at moderate temperatures), a 50 ppm (active ingredient) treatment of glutaraldehyde also maintained H2S concentrations below the minimum detectable level through the addition of live microbes after three weeks, and H2S concentrations registered 15.0 +/- 9.7 ppm H2S after four weeks. Similar time scales of protection are observed for each treatment condition through the enumeration of microbes present in each reactor. The differentiation in antimicrobial activity (and specifically, prevention of biogenic souring) afforded by DMO and glutaraldehyde suggests that such nonionic, preservative biocides are a superior choice for maintaining control over problematic microorganisms as compared to surface-active biocides like TTPC at the concentrations tested. The significant duration of efficacy provided by DMO and glutaraldehyde in this first-of-its-kind suite of simulated reservoirs demonstrates that comprehensive preservation and prevention of biogenic souring from completion through to production is feasible. Such comprehensive, prolonged protection is especially relevant for extended shut-ins or drilled but uncompleted wells (DUCS) such as those experienced during the COVID-19 pandemic. The environment simulated within the bioreactors demonstrates that the compatibility afforded by a preservative biocide offers downhole protection that cationic, surface-active biocides do not.

Abstract The necessity to verify epoxy resin sealant's reliability for well applications is amplified as its use increases. Limited data exists to confirm resin's long-term durability or chemical stability under exposure to well fluids at temperature and pressure. This paper presents laboratory results illustrating durability and stability of epoxy resin exposed to a range of well fluids over a span of temperatures. Additionally, results of accelerated thermal degradation testing further quantify long-term thermal and chemical stability. Epoxy resins formulated for a range of remedial and abandonment applications were cured in fresh water, CaCl2 brine, and hydrocarbon at 170°F up to one year. Additional samples cured in fresh water and water containing CO2 and H2S at elevated temperatures (220°F to 320°F) for up to six weeks to produce accelerated degradation reactions allowed the assessment of resin degradation verses temperature. Thermal Gravimetric Analysis (TGA) evaluated chemical and mechanical degradation verses time at temperatures ranging from 200°C to 400°C. Arrhenius calculations were performed to forecast long term stability of resins across their intended temperature ranges. Resulting data were analyzed to develop an inclusive assessment of resin stability and durability in well environments. Results indicate properly formulated epoxy resin is a mechanically, chemically, and thermally durable sealant for well applications.

Abstract Mineral scale formation causes billions of dollars’ loss every year due to production losses and facility damages in the oil and gas industry. Accurate predictions of when, where, how much, and how fast scale will deposit in the production system and how much scale inhibitor is needed are critical for scale management. Unfortunately, there is not a sophisticated scale deposition model available, potentially due to the challenges below. First, an accurate thermodynamic model is not widely available to predict scale potential at extensive ranges of temperature, pressure, and brine compositions occurring in the oilfield. Second, due to the complex oilfield operation conditions with large variations of water, oil and gas flow rates, tubing size, surface roughness, etc., wide ranges of flow patterns and regimes can occur in the field and need to be covered in the deposition model. Third, how scale inhibitors impact the mineral deposition process is not fully understood. The objective of this study is to overcome these challenges and develop a model to predict mineral deposition at different flow conditions with or without scale inhibitors. Specifically, after decades of efforts, our group has developed one of the most accurate and widely used thermodynamic model, which was adopted in this new deposition model to predict scale potential up to 250 °C, 1,500 bars, and 6 mol/kg H2O ionic strength. In addition, the mass transfer coefficients were simulated from laminar (Re < 2300) to turbulent (Re > 3,100) flow regimes, as well as the transitional flow regimes (2300 < Re < 3,100) which occur occasionally in the oilfield using sophisticated flow dynamics models. More importantly, the new deposition model also incorporates the impacts of scale inhibitors on scale deposition which was tested and quantified with Langmuir-type kink site adsorption isotherm. The minimum inhibitor dosage required can be predicted at required protection time or maximum deposition thickness rate. This model also includes the impacts of entry-region flow regime in laminar flow, surface roughness, and laminar sublayer stability under turbulent flow. The new mineral scale deposition model was validated by our laminar tubing flow deposition experiments for barite and calcite with or without scale inhibitors and laminar-to-turbulent flow experiments in literature. The good match between experimental result and model predictions show the validity of our new model. This new mineral scale deposition model is the first sophisticated model available in the oil and gas industry that can predict mineral scale deposition in the complex oilfield conditions with and without scale inhibitors. This new mineral scale deposition model will be a useful and practical tool for oilfield scale control.

Abstract Mineral scale formation has always been a serious problem during production. Most scales can be treated by adding threshold scale inhibitors. Several crystallization and inhibition models have previously been reported to predict the minimum inhibitor concentration (MIC) needed to control the barite and calcite scale. Recently, more attentions have been paid to the formation of celestite scale in the oilfield. However, no related models have been developed to help determine the MIC needed for the celestite scale control. Therefore, in this study, the crystallization and inhibition kinetics data of celestite under a wide range of celestite saturation index (SI = 0.7 – 2.6), temperature (T = 25 – 90 °C), ionic strength (IS = 1.075 – 3.075 M) and pH (4 – 6.7) with one phosphonate inhibitor (diethylenetriamine penta(methylene phosphonic acid, DTPMP) and two polymeric inhibitors (phophinopolycarboxylate, PPCA and polyvinyl sulfonate, PVS) were measured by laser apparatus or collected from previous studies. Then, based on the results, the celestite crystallization and inhibition models were established accordingly. Good agreements between the experimental results and calculated results from the models can be found. By using these newly developed models, the MIC needed for three commonly seen inhibitors, DTPMP, PPCA and PVS on celestite scale control can be predicted under extensive production conditions. The developed models can fill in the blank in scaling management strategies for high Sr2+ and SO42- concentrations in the produced waters.

Abstract Sulphate scale can be predicted from thermodynamic models and over recent years better kinetics data has improved the prediction for field conditions. However, these models have not been able to predict the observed deposits where flow disruptions occur such as chokes, gas lift and safety valves. In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that with increased turbulence there is an increase in the mass of scale observed and an increased concentration of scale inhibitor is required to prevent its formation. In this paper a field case is investigated where strontium sulphate was observed in a location downstream of a gas lift valve. Laboratory tests were conducted to confirm whether the expected scaling was observed in a low shear flow loop and also to investigate whether the location of the scale changed when additional turbulence (gas injection) was introduced to the system. The flowrate was chosen so that the shear stress generated on the test piece was approximately 1-2 Pa, similar to the value expected in typical field pipe flow. At the end of the test, the scale adhered to each of the five sections of the test piece pipe work was analysed separately to give data on both the mass and location of scale. A second test was also carried out to investigate the effect shear and turbulence induced by gas lift had on scale formation by modifying the test piece to introduce a flow of gas into the system. The test method was then used to evaluate a scale inhibitor and assess whether its performance was affected by the different flow regimes. The introduction of the ‘gas lift’ had a significant effect on the location of scale. Instead of being spread evenly throughout the test piece, the majority of the scale deposited upstream of the gas injection point. This is likely due to the induced turbulence and expansion in the tubing diameter at the T-piece increasing the residence time and thereby enhancing scale growth. A significant difference in scale location was also observed when the inhibitor dose was too low to prevent deposition and a higher dose was required to achieve complete inhibition in the ‘gas lift’ system. The findings from this study have significant impact on the design of test methods of evaluating scale risk in low saturation ratio brines and the screening methods for scale inhibitor for field application that should be utilised to develop suitable chemicals that perform better under higher shear conditions.

Abstract In the Permian basin, Spraberry Trend is one of the formations that markedly contribute to the unconventional shale production in the U.S. lately. Unusual shale reactivity was encountered while drilling several horizontal wells, leading to wellbore instability issues. Consequently, shakers’ screens blockage increased the mud losses and drilling time, leading to an increased non-productive time (NPT). This paper addresses the challenges and causes of the formation instability issues resulted from shale interaction with the used drilling fluid and presents the timely actions taken to mitigate such problems. During the drilling operation, several rock samples were collected at different depth intervals from the shale shaker. Rock samples were analyzed to identify the clay and minerals contents in the formations. The collected samples were first cleaned to remove the mud, dried, ground, and then characterized by an X-ray diffraction test (XRD) and microscopic imaging. After identifying the possible reasons for the wellbore instability, several timely actions were taken to mitigate this issue. These actions include: 1) increasing the emulsion stability, 2) increasing the water phase salinity (WPS), 3) decreasing the water phase volume, 4) adding wetting agent, 5) using wider screens for the shaker, and 6) controlling drilling parameters such as weight on bit and rotational speed. Afterward, wellbore stability, well control problem indicators, and drilling fluid properties, especially rheology, were closely monitored to identify any subsequent or unusual events. The geological and mineralogy studies show that the drilled formation contains high smectite and illite clay content, up to 49%, which was believed to be the main reason for the unusual shale reactivity. Replacing the existing screens (200 API) with wider screens (160 and 140 API) showed an insignificant effect in mitigating the screens blockage. The adopted method of reducing the rate of penetration (ROP) and increasing the circulation time helped significantly alleviate the screens blockage by reducing the cuttings production and giving more time for hole cleaning. Furthermore, the optimal hole cleaning successfully increased the formation's stability. Adding a wetting agent to the drilling mud did not impact the cuttings aggregations; however, it led to a decrease in the rheological properties; thus, adding more concentration of the viscosifier was required to maintain the fluid rheology. Increasing the water phase salinity (WPS) to over 230k ppm and the emulsion stability to over 700 mV was considered the backbone of the treatment plan that significantly resolved the issue by inhibiting the clay. Eventually, the critical considerations were pointed out.