Leakage in carbon storage and hydrocarbon wells continues to be an area of concern in the development and abandonment of reservoirs. Industry need for a leakage remediation sealant that can perform in systems beyond the capability of cement squeezes has driven the development of a CO 2 /pH activated "smart" gel. Exploratory laboratory tests and a mock field scale well test were performed to determine the effectiveness of the smart gel. Control of the smart gel particle size distribution was demonstrated through batch synthesis experiments. Microfluidic experiments show some of the mechanisms leading to the successful sealing of an engineered fracture system. Initial and subsequent testing of the deployed smart gel in a leaky mock well completion proves the effective scale up of the smart gel sealing capability and can further drive wider adoption of this unique technology.

After a blowout incident, the wellhead conditions (hydrocarbon flow rate and pressure) are difficult to predict. The worst-case discharge during an offshore blowout has always been a concern for the oil and gas industry. When a blowout occurs, the two-phase flow establishes various flow patterns along the wellbore depending on several factors such as wellbore and reservoir conditions as well as flowing fluid properties. The multiphase (gas-liquid) fluid flows upward through the wellbore at an extremely high velocity that may reach a sonic condition at the wellhead. One of the challenges for the worst-case discharge rate calculation is predicting the pressure drop and velocity of the influx in subsonic and sonic conditions. This paper presents a novel computational tool which is developed to characterize the well control events by simulating the possible worst-case discharge (WCD) scenarios under field conditions. The exactness of a WCD prediction tool is strongly related to the accuracy of models used to analyze the two-phase flow and the formation of sonic flow condition. The WCD tool developed in this study utilizes the nodal analysis technique to precisely predict the wellhead conditions post blowout incident. The tool has two main parts: i) reservoir portion, and ii) wellbore portion. The tool integrates various reservoir, PVT and production models to estimate the deliverability of a reservoir. Different forms of hydrocarbon production (oil, dry gas, and condensate) from multiple reservoir layers are considered in tool development. To forecast pressure loss along the wellbore, well-established models have been selected to make predictions for different flow patterns (bubble, low-velocity slug, high-velocity slug, and annular flows). In addition, various two-phase flow models have been modified and adapted to suit the Worst-Case Discharge (WCD) predictions. Furthermore, based on experimental observations, a new flow pattern map has been established and implemented in the model. One of the findings of this study is that the WCD rate is not only dependent on conditions of the wellbore section but it is also influenced by the fluid properties and reservoir characteristics. Therefore, the tool accounts for reservoir type, the number of producing layers, formation type (consolidated and unconsolidated), fluid types (oil, gas water, and gas condensate), and the pay zone thickness. In addition, the tool allows the user to specify fluid and reservoir properties for each layer including permeability, water, oil and gas saturation, API gravity of oil, salt concentration, bubble point and reservoir pressure, irreducible water saturation, critical oil and gas saturation, and gas specific gravity. With respect to the wellbore section, the tool provides flexible options for the user to design the desired wellbore configuration. These options comprise of the depths of cased and open-hole sections, casing and hole diameter, the roughness of casing and open-hole section and the inclination angle of the wellbore. The tool provides good WCD rate predictions for wells with an inclination up to 45° from the vertical. This article presents a novel WCD tool developed based on modified mechanistic two-phase flow models, which are validated for wide ranges of gas and liquid superficial velocities. As outputs, the tool predicts the wellhead parameters post blowout incident such as WCD rate, gas and water rates, the occurrence of the sonic condition and surface pressure. In addition, it provides an inflow performance relationship (IPR curves) for each reservoir layer. Predicting the wellhead pressure at the moment of the blowout helps to control the well by determining the density of the killing fluid.

The drive for cost efficient solutions in drilling has become stronger the last few years, and one of the approaches to this end is to increase the level of automation. Automation is multi-disciplinary task, and to really succeed, there is a need for collaboration between the different parties in the drilling industry. In this paper we discuss which underlaying technologies within instrumentation, control systems and communication technology that should be in place for a typical model-based automation and well protection software to work optimal. We elaborate on what is needed to take out the full potential of performance-enhancing functionalities in automated drilling control software. We highlight the gaps present today and how this affects the automation efforts as a whole. The discussion shows that there are some low-hanging fruits that can give significant cost reduction and improvements in automation and safety, while there are also some technology gaps that will take some time to fill and that require coordinated efforts between the vendors.

An application for Pressurized Mud Cap Drilling (PMCD) was needed to successfully drill an U.S. onshore, unconventional, High Pressure / High Temperature (HP/HT) well. The length of the lateral, highly fractured formation & extremely high MWs needed to drill the lateral proved that conventional drilling methods would not be effective, so PMCD was utilized. The main challenge was to keep circulating pressures low while injecting the circulating fluid into the naturally highly pressurized formation. PMCD involves injecting / losing the circulating fluid (water) into the formation, in this situation, high formation fracture pressures required high surface injection pressures to push the fluid & cuttings into the formation. When the injection pressure was combined with the frictional losses through the drill string, anticipated surface pressures were over 10k psi when circulating. To combat the high circulating pressure, an approach was taken to use Friction Reducer (FR) in the circulating fluid, water, thus reducing the frictional pressure loss while circulating within manageable constraints. This paper will go into detail of the different phases taken to determine the appropriate type of FR based on lab testing, hydraulics model, temperature modeling, and the results from the application of the product in the drilled well. Extensive hydraulics modeling was conducted to determine the feasibility of using the FR and the final anticipated circulating pressure. The BHA and drill string design was optimized to maximize the least amount of pressure drop across the tools while staying within operating parameters. Concerns of the use of FR such as ECD effect, fluid flow characteristics for hole cleaning in the annulus, temperature effects of the water being pumped, and effects in the BHA were all considered in the engineering process. FR testing including, lab testing of the base fluid (water), differential scanning calorimeter to determine effects of BHT, FR shear testing, FR concentration percentage at various flow rates in a flow loop to calculate Reynolds number at the respective flow rates & concentration and differential pressure testing with time and temperatures. Based on the results from the hydraulics modeling and lab tests, an FR was selected and fully utilized in the application of the product. PMCD techniques with this FR was used and was fully successful in the intended reduction of the surface circulating pressures while drilling the well. Surface and downhole results captured the effects of the FR in the fluid system and data was collected and analyzed to show the expected vs actual results on various drilling parameters.

Achieving mobility control of steam in porous media has been approached by the implementation of foaming surfactant additives; however, foam generated with surfactants lack stability at high temperatures (≥ 200 °C). In this study, a nanofluid was formulated for steam co-injection to address common issues with surfactants as steam additives. The nanofluids were formulated using synergistic interaction of nanoparticles and surfactants (both readily available) to address thermal stability, and foam stability at the conditions encountered in thermal enhanced oil recovery processes such as steam assisted gravity drainage. Zeta potential analysis, static tests, and high temperature aging tests were performed to obtain the ideal mixture of nanoparticles and surfactants. A steam/foam core flooding apparatus was used to evaluate the mobility reduction of nanofluids using multiple differential pressure transmitters situated along the length of a 40 cmsand pack to confirm foam propagation. The tests were first conducted at 200 °C with nitrogen as a non-condensable gas carrier. Upon confirming nanofluid mobility reduction characteristics at 200 °C with gas, a successful nanofluid was co-injected with superheated steam at backpressure corresponding to a saturation temperature of 200 °C inside an oven with that set point. Mobility reduction characteristics were obtained for each formulation by normalizing the differential pressure of additive multiphase flow to their respective baselines. Statictests and high-temperature core floods demonstrated a strong synergy between appropriate combinations of surfactants and nanoparticles.None of thesurfactants and nanoparticlesyielded mobility reduction when used on their own; however, when selected according to a design basis, nanoparticle/surfactant mixtures exhibit strong mobility control with steam as well as hot gas. The foam produced in the porous media was held in a visual cellat 150 °C for 24 h with no loss in foam height. Furthermore, foam generated with the nanoparticle-surfactant hybrid remained stable in static tests in the presence of heavy crude oil for more than one week. The primary novelty of this study is the ability to use less exotic surfactants and nanoparticles as steam mobility control agents, increased foam stability in the presence of oil, and demonstrable synergy between commodity molecules (i.e., surfactant) and nanoparticles at steam flooding conditions. The successful additive mixture was developed with scalability in mind such that manufacturing will not hinder the feasibility of scale-up for industrial use.

Affinity law teaches that when the rotating speed of the electric submersible pump (ESP) pump is tripled, the flow rate triples and the head increases to nine times the original pump. Thus, a high-speed ESP has the potential of delivering increased production at deeper setting depths and opportunity for shorter equipment allowing operators to land the equipment in shorter tangent sections. Operation at high-speed also presents additional challenges with one of the most significant being increased potential for abrasive and erosive wear. This study compares pump performance from slurry testing to help evaluate the potential trade-offs system performance versus wear when operating at higher speeds. When deploying ESPs in sandy applications, sand particles can enter the seal clearance between impeller and diffuser creating 3-body abrasion wear. Meanwhile, the 2-body erosion wear in stage flow path reshapes the hydraulic geometry and causes additional losses. Both abrasion and erosion cause pump head reduction, efficiency deterioration, and thrust increase. Data was collected during slurry testing for comparison of performance over the test period. The in situ head change and thrust change were monitored during the slurry test. Pre and posttest stage dimensional data were gathered for comparison. Sand samples were gathered and analyzed to ensure similar slurry conditions applied to all the tested pumps. Slurry testing and analysis for the evaluation of ESP pump stage performance deterioration for a stage operated at 10,000 RPM as compared to a stage operated at 3,500 RPM will be provided. The pump performance degradation and dimensional wear were compared. This demonstrates higher speed ESP pump components can be created that show similar abrasive wear performance to current ESP pump. A 10,000 rpm ESP pump completed slurry testing while measuring pressure, temperature, flow and thrust. The results provide pump performance deterioration trend in a sand application and helps to understand physics of stage wear mechanism. This is the first of this type of testing apparatus to authors’ knowledge. It also serves as a backbone in high-speed pump validation program.

Two of the most important parameters to monitor during a primary cementing job are the flow rate in and return flow rate measurements. To achieve optimum quality control of a primary cementing job, measuring annular return rates and comparing them with simulated data in real-time will provide better understanding of job signatures and result in the best possible top-of-cement estimation prior to running any cement evaluation log or taking decision to continue drilling the next section of the well. The return rate job signature along with the wellhead pressure is essential to understand the behavior and discrepancies between simulated and acquired surface data. Therefore, to assess the risk of job issues, such as unsuspected washout and lost circulation among others, accurate measurements of the return rate are critical. Historically, cement job evaluation has been limited by the fact that most drilling rigs do not have an accurate flow meter installed on the annulus return line, and a simple verification of mud tanks volumes versus pumped volume, as reported by drillers or mud loggers, more than often results in an unreliable assessment of the volume lost downhole, due to the unfamiliarity with the U-tubing effect and lack of data consolidation from the cement unit (flow rate in) and the rig (flow rate in & flow rate out). This paper will review a solution developed to mitigate the lack of a direct flow rate measurement by computing and displaying the return rate using either a paddle meter measurement or the derivative over time of the volume observed in the rig tanks.

Hydraulic fracturing is a widely applied technology to increase recoverable reserves and accelerate production in low permeability reservoirs. In this technique, the hydraulic fractures are generated by pumping a fracturing fluid at a high flow rate and introducing proppant with the fluid to keep the fractures open after the pumping is halted. In horizontal well fracturing, one of the most important factors in this method is the proppant transport and distribution in the wellbore and among perforation clusters. Uneven proppant distribution between multiple clusters/fractures can cause a drop in the near-wellbore fracture conductivity, which in turn causes a negative impact on the production performance of the hydraulic fractures. This paper presents new experimental correlations that were developed and can be utilized to predict the proppant distribution between subsequent perforation clusters. The experimental correlations were developed using dimensional analysis from appropriate experimental data. The experimental data for this study was obtained from a horizontal wellbore apparatus with three perforation clusters at shot densities of 4 SPF with 90-degree phasing. Several experimental tests were conducted on 20/40 and 40/70 for white sand (SG of 2.65) and ultra-light weight ceramic (SG of 2.0) using freshwater fluids at three flow rates and over a wide range of proppant concentrations. Four types of experimental correlations were developed by experimentally investigating the effect of each parameter on the proppant distribution between the three perforation clusters. The first correlation type developed is based on the proppant concentration, while the second type is based on the flow rate and proppant concentration. The third correlation type includes the particle median diameter as another independent variable, along with the flow rate and proppant concentration. The fourth and final correlation developed consists of the proppant density along with the proppant median diameter, flow rate and proppant concentration as its independent variables. This fourth and final correlation was validated by comparing the predicted values to the laboratory values. The results of correlation analysis comparison to lab data show that the 20/40 and 40/70 ULW ceramic showed the lowest average error values at 2.92% and 1.56%, respectively, while the 20/40 and 40/70 white sand transport predictions were reasonable (average error range of 3.67% - 11.67%). The low error values indicate the high reliability of the developed correlations in predicting the proppant distribution between perforation clusters. To the authors’ knowledge, the developed correlations are the first of their kind to be based on experimental data. These correlations can help to determine the optimum flow rate that is required to attain even distribution of the proppant and provide more insight about the anticipated proppant distribution into and out of perforation clusters.

Oil and gas gathering systems can experience flow instabilities characterized by cyclic pressure variations and liquid or free water surges out of the flowlines that typically cause liquid or gas handling problems in receiving facilities and dynamic external loads in elbows and T-junctions. This study describes a new mechanism of instability of gas-liquid flow in a well-flowline-receiving facility system referred to in other industrial applications as the density or liquid holdup wave oscillations (DWO). Unlike instability phenomena related to hydrodynamic slugs, terrain-induced slugs or riser-induced severe slugging, this type of instability is a result of multiple feedback effects between the flow rate, pressure drop, and liquid inventory (the total volume) in the flowline. The specific DWO instability mechanism proposed in the present study is related to generation and propagation of a liquid holdup wave with a large amplitude and wavelength several times greater than the length of a hydrodynamic or terrain-induced liquid slug. A new stability criterion to predict the DWO onset is proposed based on Ultra-High Definition (UHD) simulations of three-phase gas-oil-water flow to accurately predict the liquid inventory. Field data showing a transition from unstable to stable operation in an offshore oil production system are presented. The system is used to transport produced fluids from a satellite platform with naturally flowing and gas-lifted wells to a central platform with processing facilities, via a 30-in. diameter flowline. The stability criterion was used to identify the root cause of large-amplitude oscillations of pressure and flow rate in the flowline. Thus, proposed dynamic two-phase flow instability mechanism and criterion are a cost-effective and practical method for predicting instability onset conditions and developing mitigation strategies in existing and new-built production facilities.

Improper hole cleaning is a major cause of non-productive time (NPT) in drilling. Current hole cleaning practices are mostly based on experience, rules of thumb and simplistic calculations. Hence, they are not reliable and do not work as expected in all scenarios. There is the need for a robust, fast, and accurate approach to simulate cuttings transport, and provide reliable and useful estimations of the hole conditions in real-time. In this paper, a transient cuttings transport model is presented for real-time hole cleaning simulations. The model solves the transient conservation equations using a drift-flux modeling approach, which is applied to describe the multiphase flow of cuttings and fluid in the wellbore. The model uses experimentally derived equations that account for the effects of pump rate, pipe rotation, eccentricity, fluid rheology, inclination, etc. on cuttings transport. A fast numerical solver is used to enable real-time simulations, while providing numerical stability that is crucial to maintain the modeling convergence under area discontinuities. Using small time-steps, the model captures pressure wave behavior, which is necessary for simulating managed pressure drilling (MPD) operations. Pressure-dependent mud density, non-Newtonian viscosity, and cuttings slip velocity models are used to estimate downhole parameters such as pressure, cuttings concentration, bed height, drilling fluid and cuttings velocities, etc. The model can provide a drilling crew with accessible real-time simulation results on the rig for monitoring the hole cleaning operation and preventing problems from happening. Case studies are performed based on field experiments to analyze the effectiveness of the developed model on avoiding operational problems such as pack-off and stuck pipe. Results show that by monitoring the real-time cuttings concentration and bed height along the wellbore, the developed model can detect improper hole cleaning conditions and provide optimum drilling parameters to resolve problems, thereby minimizing NPT. The robust numerical scheme allows for simulations that are several times faster than the real-time operation on a standard desktop PC, providing the crew with enough time to take preventive actions. Clean-up cycles can also be simulated by the model to calculate and optimize the required parameters for optimum hole cleaning results. Required clean-up times are calculated for the field cases to ensure that cuttings are effectively removed from the wellbore before pulling out of hole and running casing. Moreover, MPD operations can be simulated using the model that consider the effects of cuttings concentration and bed blockage on the pressure profile. The developed model can provide valuable real-time information on downhole conditions to the drilling crew during the drilling process and give adequate time to the crew to take timely corrective action if necessary. Moreover, the model can simulate the planned drilling process and calculate optimum drilling parameters to avoid hole cleaning problems.

More than 35 million m 3 of oil have been produced from the Mittelplate oilfield. Poor hole cleaning has been identified as a root cause for drilling problems in the horizontal sections of its ERD wells. Enhancing cutting removal in vertical wells, high-viscous pills are typically considered. However, literature is providing contradicting guidance of using sweep pills in deviated/horizontal wells. Thus, the purpose of this study is to provide an overview about the theoretical background on hole cleaning and to experimentally identify the best sweep pill for ERD wells. An apparatus has been designed as a closed flow-loop system consisting of coaxial pipes forming a horizontal well with a drill-string inside, two mud tanks, and a mud pump. Two pressure sensors are placed along the horizontal section, providing complementary information about the moving sweeping pill. Different pills (high-viscosity, medium-viscosity, high-density and a high-viscosity/high-density combination pill) have been circulated and the recovered model cutting material from one cycle of circulation has been re-weighted. To the best of our knowledge, it is the first time that such a fully scaled-down device including pressure sensors at the toe and heel of the horizontal section has been designed and used for the evaluation of sweep pills. It delivers an efficient and cost-effective method to optimize hole cleaning processes and prevent costly drilling incidents.

Injector well completions are typically carried out using two methods: simple and selective. The performance of injector wells has traditionally been evaluated using spinner-based injection logging tools (ILTs) or on-demand fiber optic distributed temperature and acoustic (DTS or DAS) sensing while logging the well performance every 3 months or once a year depending on the application. However, with such methods utilizing a snap shot approach, critical well performance information or possible anomalies are often missed due to measurements taken only during certain periods. Therefore, operators have explored the use of advanced fiber-optics methods such as permanent distributed temperature sensing (DTS) and permanent distributed acoustic sensing (DAS), that provide continuous, real-time measurements to enable understanding of dynamic well behavior at all times and mitigate any deferred or behavioral problems. Of relevance to this work is a vertical, injector well in a competent sandstone formation of the Heavy Oil Chichimene field in Llanos Basin, Colombia. As a first step of the fiber-optics monitoring strategy, a careful evaluation of DTS and DAS based fiber-optics methods was conducted. Based on the data analysis and operational history, DAS-based fiber optics monitoring was chosen as the most effective monitoring solution for this well. Subsequently, a proprietary DAS algorithm was developed to analyze the data and estimate the flow allocation for all the four zones. The results include waterfall acoustic energy maps, temporal flow allocation profiles and most importantly, the zonal flow allocation values. Predicted (DAS) zonal flow allocation data was compared with traditional injection logs (ILT) under different operational conditions (varied injection flow rates and valve choke settings). Based on comparable agreement between DAS and ILT data, the operator decided to replace ILT runs with DAS-based fiber optic monitoring, resulting in lower operational costs while enabling near real-time monitoring, and providing the continuous distributed data essential for the dynamic monitoring of the well. The successful application of fiber-optics monitoring to provide an injection profile in conjunction with a surface-controlled electric valve system demonstrates a significant potential to optimize the injection process in complex injector wells. Further, remotely controlling, monitoring and optimizing injection rates into the multi-segmented zones improves the service life of the injection operations, eliminates future intervention costs, and increases ultimate recovery.

This paper investigates the effect of variable perforation configurations on proppant transport, settling, and distribution across different perforation clusters in multistage horizontal wells. The results are compared to other previously published data ( Ahmad and Miskimins, 2019 ) using different proppant sizes and densities. A 30-foot horizontal laboratory apparatus with three perforation clusters is used to simulate a multistage horizontal well. Low viscosity fresh water is used as the carrier fluid to transport the proppant. This research incorporates the influence of testing various injection rates and proppant concentrations on proppant transport of 100-mesh brown sand. Different perforation configurations are used to test the perforation effect on proppant transport using similar injection rates and proppant concentrations. A 200-gallon tank is used to mix the proppant before injecting the slurry mixture using a slurry pump. The apparatus also incorporates a variable frequency drive, a flow meter and pressure transducers. Sieve analysis is then conducted to identify the proppant distribution exiting from each cluster at different perforation configurations. It commonly assumed that the injected proppant is distributed evenly across the perforation clusters and that the distribution of fluid and proppant is identical. However, this research shows that this is not always the case. The results show uneven fluid and proppant distributions between clusters when altering the perforation configurations, injection rates, and proppant concentrations. Sieve analysis also shows different size distribution of the settled and exited sand through different clusters and individual perforations. Such information is beneficial to understanding transport in horizontal, multi-stage completions and how such impacts the overall treatment efficiency.

We describe the first field applications of a new multifunctional foaming agent (MFA) for production enhancement in oil wells with gas lift. The tests were conducted in three wells with water cuts from 40 to 90%, depth (>5000 m), bottomhole temperature (150°C), and brine hardness and salinity up to 180,000 ppm and 310,000 ppm TDS, respectively. The MFA was coinjected with lift gas via the annulus and generated foam downhole as it mixed with reservoir fluids in the tubing. Tested MFA concentrations ranged from 160 to 750 ppm. The field tests demonstrated that the MFA was able to increase the oil production for a fixed gas lift injection volume. The MFA also enabled to reduce lift gas consumption, while maintaining or even increasing the original oil production.

Limited entry is used in multistage fracturing to attempt to distribute fracture fluid among multiple perforation clusters evenly. As the slurry is pumped through perforations, the perforation holes can be eroded because of abrasion by the proppant, and therefore become enlarged, resulting in less effective limited entry and lower efficiency of the fracture treatment. Distributed Acoustic Sensing (DAS) is a method used for monitoring of fluid flow during hydraulic fracturing. By evaluating the changing DAS responses at perforation cluster locations during fracture pumping, DAS can be used to evaluate perforation erosion. DAS is a measurement of acoustic energy induced by fluid movement with fiber optic sensing cables. A raw acoustic signal recorded by the interrogator is transformed into an energy response (Frequency Band Energy), which is used for further interpretation of fluid volume distribution among perforated clusters on each stage of the fracturing treatment. Based on previous laboratory experiments and computational simulations, there is a correlation between the Frequency Band Energy and fluid flow rate. As the flow rate is a function of fluid velocity and perforation area (diameter of perforation), the same flow rate could be attained with a combination of different velocities and areas, leading to a non-unique solution when interpreting DAS measurements. We transferred the correlation into the relationship between velocity and Frequency Band Energy, using the perforation area as an additional parameter. It enforces avoiding non-unique solutions in the interpretation process. Perforation diameter is a function of erosion rate, which depends on the proppant concentration and velocity of fluid passing through the perforation. In order to connect correlation parameters with the diameter of perforations, computational simulations of fluid injection were conducted with different perforations geometries. Based on these simulations, a function that connects the area of perforation with a correlation parameter was obtained. It allows us to include the diameter of perforation in the analytical equation explicitly. The application of the enhanced correlation in the interpretation process leads to increased accuracy of the fluid distribution calculation. For each time step, the velocity of the fluid, the mass of proppant, and the diameter of the perforations are computed, allowing the calculation of the flow rate in each perforation cluster. Perforation erosion is included in the model. Examples using field data are presented in the paper.

Multiphase flow behavior in a wellbore is inherently coupled with a reservoir, which is controlled by pressure boundaries. Most of the previous experimental studies in the laboratory have been performed at constant liquid and gas mass flow rates boundary conditions. This study experimentally compares the gas-liquid flow behaviors between constant pressure and constant mass flow rates boundary conditions in a toe-down horizontal well and investigates the effect of constant pressure boundary on the system stability. The experiments were conducted in a large-scale experimental facility to study the flow behavior in a toe-down horizontal well. They were performed at two different permeabilities for a constant pressure boundary (CPB) condition. Results were compared against experiments with constant mass boundary (CMB) conditions from different aspects, including outflow performance relationship (OPR), liquid holdup, and dynamic analysis. The experimental study on system stability was analyzed for three different operating conditions, namely, constant flow rate, constant gas liquid ratio (GLR), and constant liquid permeability. Similar tests were also studied using a numerical simulator. The results show that the time-averaged OPR and liquid holdup from constant mass and constant pressure boundary conditions match well. However, the amplitude of pressure and flow rate fluctuations are different, which causes the instabilities on the left side of the minimum of the OPR for high gas permeability reservoir at CPB conditions, where production persists for the CMB. The amplitude of pressure and gas rate fluctuation depends on reservoir permeability. It is found that the multiphase flow behavior in the wellbore for a constant mass boundary is closer to that for low permeability reservoirs, which commonly occur in shale plays. The total liquid inventory decreases as superficial gas velocity increases, and the fluctuations in superficial gas velocity have no evident impact on its behavior. Both experiments and numerical simulations show that system instability also depends on reservoir permeability. Stable production still exists on the left of the minimum OPR if the permeability is sufficiently low.

Bottom water, which is defined as a zone below the base of bitumen pay with high water saturation, has been encountered in many currently operated steam-assisted gravity drainage (SAGD) projects. It has been widely accepted that the bottom water lying under bitumen in SAGD act as a heat sink which is a result of the much higher mobility of water compared to that of the bitumen. This has a detrimental effect on the project economy because of the resulted greater steam-oil ratio (SOR) and less oil recovery. Therefore, it is essential to reduce the mobility of bottom water in SAGD operations to avoid the water coning and steam loss to the bottom water. In this study, emulsion-based conformance control treatment is introduced and investigated in oil sands reservoirs to reduce the mobility of bottom water to avoid the water coning and steam loss to the bottom water during the SAGD operations. To accurately simulate the emulsion plugging performance during the SAGD process, it is essential to optimize the emulsion flow model in water saturated porous media to better describe the flow mechanism. There are three main mathematical models applied to describe the dynamics of emulsion flow in porous media: the bulk viscosity model, the retardation model and the filtration model. In this paper, the newly proposed emulsion flow model was optimized on the basis of the conventional filtration model with considering the process of emulsion droplets trapped and released by the pore throats. Three different types of emulsion flow tests were collected and analysed from previous publications, including permeability reduction of an emulsion in a specific sandpack, an emulsion slug injection followed by water injection in a specific sandpack and conformance control performance in parallel-sandpack. The optimized emulsion flow model can successfully simulate all of the three different types of emulsion flow process and have a good agreement with the experimentally obtained results. A new method for predicting permeability reduction by emulsion plugging was firstly determined by fully incorporating with the emulsion and sandpack properties. By successfully simulating the emulsion plugging process in a specific sandpack followed by water injection, a desired conformance control performance can be predicted by injection of a prepared emulsion in a specific parallel-sandpack. This may give an instruction on optimal emulsion design in the field application. The optimized emulsion flow model shows a wide application in different types of experiments and flexible control on the parameters, showing a huge potential for the reservoir-scale simulation.

The litmus test for downhole multiphase flowmeters is to compare the measured phase flow rates with the test-separator rates. In most cases, the composition of the measurand is required for flowmeters and is typically obtained from bottomhole fluid samples. Extracting and analyzing fluid samples is an expensive process mostly done at the initial stages of field development. Because the composition is not always available and is usually old, flowmeters may have subpar performances when compared to test separators. In this work, it is shown that once the test-separator data are available, measuring mixture sound speed downhole will ensure the optimization of a multiphase flowmeter system without needing to obtain new fluid samples. This novel method is demonstrated in a North Sea case history. This method of optimizing flow rates is independent of the measurement device because the required flow velocity and sound speed measurements could be obtained from separate and generic devices. For example, the fluid bulk velocity and mixture sound speed could be measured by a point measurement device and a distributed acoustic sensing (DAS) system, respectively. The main challenge in a flow-velocity/sound-speed measurement system is to determine individual phase sound speeds so that the mixture phase fraction could be correctly modeled using Wood's mixture sound speed model. The phase fraction from the separator tests could be used as the target value to optimize the performance of the system. This is done with a backward calculation of the sound speed of individual phases. Pressure and temperature variations at measurement locations as well as the pipe compliance effects are also accounted for in this approach. Following the adjustment of individual phase sound speeds, a forward calculation using the same model yields a phase fraction close to the actual value, which could be improved further by an iterative approach. A downhole optical flowmeter in a North Sea field measured mixture velocity and sound speed. Well test results indicated that the water cut was underreported and phase flow rates did not match the test-separator rates. Instead of halting production and going through a fluid sample analysis cycle, the test-separator water cut was used as the target value to optimize oil phase sound speed using Wood's model with a backward calculation. The difference in oil sound speeds was extrapolated to other pressure and temperature conditions, and forward calculation showed that separator tests and flowmeter measurements closely matched. Subsequent flowmeter and test-separator data confirmed excellent agreement. Using well test data and sound speed to optimize phase flow rates is a novel method that has not been previously demonstrated. This method is independent of device type, broadly applicable, and furthers the understanding of multiphase flow measurement.

This work experimentally investigates the impact of gas bubbles on the thermal and acoustic energy prorogation within the wellbore, at various water and air flow rates using Distributed Acoustic Sensing (DAS). This is the first study that experimentally investigates the thermal and acoustic propagation at both single and two-phase flow conditions using DAS. Our results will improve the production logging algorithms especially at multiphase flow conditions, benefit the detection of gas leakage in the vertical section of a wellbore, as well as pipeline flow monitoring. Distributed Fiber-Optic Sensing (DFOS) based production logging has drawn much attention in recent years. Comparing to conventional production logging tools, fiber-optic cables can endure much harsher borehole environments and can be deployed at a lower cost. This work presents an experimental study of using DAS to track the thermal slugging in single-phase (liquid) and two-phase (gas and liquid) flow within a vertical wellbore to estimate flow velocity and characterize multiphase flow behavior. A vertical flow loop is constructed for this research, which consists of a 7-m long transparent polyvinyl chloride (PVC) test section with a 1-inch pipe inner diameter. A single-mode optic fiber with thin plastic coating is wrapped evenly around the PVC pipe, with a fiber-to-pipe length ratio of 10.7. Tap water and compressed air are used as the testing fluids. The water and air are injected at the bottom of the test section, similar to field conditions where oil and gas mixture flows into the wellbore from the bottom. The water is directly supplied from the building water system without using an additional pump to minimize the unrelated acoustic noise. Air is supplied from an air tank charged by the building compressor with a maximum pressure of 80 psi. A peristaltic pump is used to inject a small amount of hot water (< 2% of the minimum water volume from the inlet) to generate thermal slugs at the bottom of the test section. For the case of single-phase water flow, the velocity of the thermal slugging signal is similar to the actual water velocity, as expected. For multiphase flow, the thermal signal looks almost identical with that for single-phase, although the bubble velocity is much higher than the water velocity. This observation indicates that gas, with low thermal capacity and in its bubble form, cannot carry enough heat to perturb the thermal slugs in the water severely. However, a detailed analysis of the thermal slugging velocity indicates a small increase with an increase of air flow rate. We interpret that the thermal slugging velocity is associated with the actual water velocity. The existence of the gas bubble decreases the effective water holdup (cross-sectional area occupied by the water phase) in the pipe. We find that, with a constant water volumetric rate, smaller holdup leads to higher in-situ water velocity, thus higher thermal slugging velocity. The decay of the thermal slugging signal is also analyzed. The signal decay is due to the heat exchange between the fluid and the surrounding, as well as between the warmer and cooler fluid within the pipe. We observe a faster signal decay associated with a higher bubble rate, which indicates a faster heat exchange rate with the existence of gas bubbles. Multiple physical processes may cause this correlation. First, as the gas bubbles travel through the water with a higher velocity, they generate local turbulence in the water phase and accelerate the heat exchange within the water. Another possibility is that the gas, although with much smaller thermal capacity, carries heat from the warmer section to the cooler section, therefore accelerating the thermal equilibrium process. The comparison between the single-phase water and two-phase air-water experimental results indicate that the gas bubbles generate acoustic energy as they move through the pipe. Even in the low-frequency DAS data band (<0.5 Hz), it appears that the higher background noise-level is associated with the rising bubbles. Detailed analysis of the DAS data indicates individual bubbles can be traceable if they are separated more than a gauge length.

Nitrogen (N 2 ) and Carbon Dioxide (CO 2 ) foams have been used as hydraulic fracturing fluids for several decades to reduce water usage and minimize damage in water-sensitive reservoirs. These foam treatments require gases to be liquefied and transported to site. An alternative approach would be to use natural gas (NG) that is readily available from nearby wells, pipelines, and processing facilities as the internal, gaseous phase to create a NG-based foam. Hydraulic fracturing with NG foam is a relatively inexpensive option, makes use of an abundant and often wasted resource, and may even provide production benefits in certain reservoirs. As part of an ongoing development project sponsored by the Department of Energy (DOE), the surface process to create NG foam is being developed and the properties of NG foam are being explored. This paper presents recent results from a rigorous pilot-scale demonstration of NG foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures. The Pilot-scale Foam Test Facility (PFTF) used in these investigations is first described. The PFTF is capable of generating foamed fluids at pressures up to 7,500 psig and at temperatures in excess of 300°F. Then, results from several investigations aimed at proving NG foam at conditions relevant to the field are presented. NG foam was characterized using rheology measurements and flow visualization techniques. Experiments were performed to investigate the texture and stability of NG foam generated by two different mixing methods: one using a custom designed tee to match mixing velocities in the field where the gas phase is jetted into the aqueous stream, and another to ensure comprehensive mixing for laboratory analysis. Parametric studies were conducted to explore the effects of flow rate, foam quality, and temperature on the stability of NG foam. Moreover, different fluid preparations were used to investigate the effect of base fluid and additive concentrations on the stability of NG foams. Additional laboratory studies that investigated foam stability with produced water and multicomponent NG mixtures are also reported. The NG foams explored in these investigations exhibited typical, shear-thinning behavior observed in rheological studies of N 2 - and CO 2 -based foams. The measured viscosity and observed stability indicate that NG foams are well suited for fracturing applications. Like other foams, NG foam exhibits sensitivity to operating temperature characterized by a decrease in apparent viscosity as temperature increases. Rapid foam breakdown was observed at significantly elevated temperatures exceeding 290°F. In addition to fluid characterization, these investigations also yielded several key lessons that should be applied to future field demonstrations of NG foam.