Bottom Hole Injection Pressure Research Articles

Optimal Injection Parameters for Enhancing Coalbed Methane Recovery: A Simulation Study from the Shizhuang Block, Qinshui Basin, China

The injection of N2 into coal reservoir has great potential in improving recovery of coalbed methane (CBM). In this study, a numerical model was established based on the GEM component model to evaluate the influences of different N2 injection parameters (production injection well spacing, gas injection timing, gas injection duration, gas injection rate, and the bottom-hole injection pressure) on the production of CBM in the Shizhuang Block of Qinshui Basin, China. Based on the economic benefit of CBM production, the production increasing rate and nitrogen replacement ratio were established to optimize the N2 injection parameters. The results show that (1) the production injection well spacing had the greatest influence on CBM production, followed by injection duration and the bottom-hole injection pressure, and injection timing and injection rate had a relatively small influence. (2) With increasing gas injection duration, injection rate, and the bottom-hole injection pressure, the rate of production increased and the nitrogen replacement ratio decreased. (3) The optimal N2 injection scheme was revealed with the production injection well spacing of 180 m, the injection timing of a second year after gas production, an injection duration of 7 years, an injection rate of 5000 m3/d, and a bottom-hole injection pressure of 10 MPa. Under these conditions, the rate of production increasing rate, the nitrogen displacement ratio, and the regional recovery of the four production wells were 18.14%, 0.5, and 48.96%, respectively, some 8.88% higher than that without nitrogen displacement, showing good effect in terms of CBM production.

Incorporating phase behavior constraints in the multi-objective optimization of a warm vaporized solvent injection process

The warm vaporized solvent injection process has been proposed as a more environmentally friendly alternative to steam-based technologies for bitumen recovery. The process typically involves injecting heated solvent vapor into a horizontal injector; the solvent condenses and dissolves into bitumen, while the diluted oleic phase would flow towards a horizontal producer. Despite the promising results reported from several pilot projects near Fort McKay, Alberta, successful commercial-scale extraction is costly and would require a detailed optimization of the pertinent design variables. The main challenge is that this is a multi-objective optimization (MOO) problem, which aims to balance the trade-offs between conflicting performance objectives while honoring the various operational constraints. In this study, a systematic workflow is formulated to optimize these multiple conflicting performance objectives considering phase behavior constraints. A 2D synthetic model based on typical Athabasca oil sands properties is constructed to simulate the warm vaporized solvent process. The addition of non-condensable gas (methane) into the solvent (propane) is examined. The resultant changes in thermodynamic properties and equilibrium phase behavior are considered in determining the practical limits of the decision variables (e.g., bottom-hole injection pressure and temperature). The objective functions, including oil recovery factor, solvent retained-to-oil ratio, and energy consumption, are defined, and a factorial experimental design is employed to identify a subset of decision variables that exhibit minimal redundancy internally and create the dataset for proxy model development. To reduce the computational costs associated with reservoir simulations, proxy models, e.g., the artificial neural network (ANN), is developed and applied. Finally, a Pareto-based MOO scheme is implemented to estimate the optimal decision variables. Despite the higher front-end loading requirement of the ANN proxy modeling, the MOO with proxy modeling still requires significantly less execution/running time as compared to a MOO with traditional flow simulation (e.g., a 97% reduction in CPU time). This reduced running time is important for alleviating the computational load when evaluating the objective functions during the optimization process. More importantly, this optimization scheme is capable of identifying a set of optimal decision variables. This work presents a practical workflow for optimizing various design variables associated with many solvent-based bitumen recovery processes. Specific considerations including the practical limits for operating constraints and computational efficiency are examined and incorporated. It is anticipated that this workflow can be readily integrated into the design and decision-making processes in reservoir management.

A prediction model of wellbore temperature and pressure distribution in hydrocarbon gas injection well

For the sake of solving the problem that it is difficult to dynamically monitor the wellbore temperature and pressure of hydrocarbon gas injection well and accurately predicting the bottom hole injection pressure, a mathematical model to describe wellbore temperature and pressure distribution is presented according to the heat transfer principle, the energy conservation law and the momentum theorem. The Shiu-Beggs wellbore temperature calculation method is used in this model to avoid errors caused by inaccurate thermodynamic parameters, and the pressure gradient equation is modified by introducing correction coefficients to improve the calculation precision of the model in practice. The fourth-order Runge-Kutta method was used to solve the model, and the new model was analyzed and verified by actual field data. The results show that the wellbore temperature is nonlinearly distributed, while the wellbore pressure is linearly distributed, and the bottom hole pressure calculated by this model is more accurate than that calculated by other methods. This study can play a certain guiding role for the injection scheme design of hydrocarbon gas injection well.

Technical Feasibility of Using Frac-Packed Wells for Producing Natural Gas from Offshore Gas Hydrate Reservoirs

This paper presents a feasibility analysis of using frac-packing completion techniques to produce natural gas from offshore gas hydrate reservoirs. A case study was carried out for the gas hydrate accumulations in the northern South China Sea. The feasibility analysis covers the requirements of proppant size, fluid injection rate, fracturing pressure, and well productivity. For the median grain size of sediments in the studied formation from 2.60 to 28.96 μm with an average value of 8.49 μm, the required range of proppant size is between 333 mesh to 748 mesh (0.001 inch ~ 0.003 inch). Since the proppants in this size range are not commercially available, it would be economical to use screened natural sands as proppants in frac-packing operations. The minimum flow rate of fracturing fluid required to carry the 0.003 inch proppant/sand into the fracture tip at 510 ft is 3.64 bpm, which is much lower than the practical values ranging from 20 bpm to 100 bpm. Therefore proppant/sand transport during frac-packing is not a concern. To create a horizontal fracture of 510 ft radius with a fracturing fluid injection rate of 72 bpm, the maximum bottom hole injection pressure is predicted to be 2,378 psi, which is only 334 psi above the reservoir pressure and can be handled by most pumps used in frac-packing operations. Well productivity forecast with a simplified mathematical model shows that a commercial gas production rate of 16 MMscf/day is achievable with the fracture radius of 510 ft. However, the model requires further validation.

Polynomial and nonparametric regressions for efficient predictive proxy metamodeling: Application through the CO2-EOR in shale oil reservoirs

An integrated optimization workflow combining Particle Swarm and Non-parametric Proxy Metamodels was adopted with reservoir simulation to optimize oil production in CO2-EOR in shale oil reservoirs. The cyclic-CO2 flooding optimization consisted of injection, soaking, and production durations over the prediction period. Also, Minimum bottom hole pressure, maximum oil production rate, and water cut were optimized for the production wells, and maximum bottom hole injection pressure and maximum gas injection rate were optimized for the injection wells. To reach the optimal solution, 176-candidate solutions were created as training experiments with 4 successive iterations of approximately 20 experiments each. The optimal solution increased oil production by 322,675 surface barrels. Next, a 2nd order polynomial regression, Multivariate Adaptive Regression Splines and Random Forest Model proxy models were constructed to metamodel the large reservoir simulator. The polynomial proxy has the least prediction error among other approaches to simplify the reservoir evaluation and optimization process.

Incorporation of Homogenizer in Nanoemulsion Injection Scheme for Enhanced Oil Recovery

This work presents a theoretical approach of incorporating a homogenizer within a nanoemulsion injection scheme for enhanced oil recovery (EOR). Nanoemulsions are kinetically stable emulsions stabilized by surfactants with droplet sizes ranging from 20 to 500 nm and have the potential to deliver chemical agents depending on their application. For EOR, nanoemulsions have the potential to be more effective than the often used microemulsion which are thermodynamically stable and thus may break due to the heterogeneous conditions inherent in oil and gas reservoirs. There are two primary categories of nanoemulsion formulation which are high energy methods and low energy methods. High energy methods involve creating nanoemulsions using a high energy process such as high pressure homogenization. These methods can be expensive due to the energy applied to the nanoemulsion formulation process. Low energy methods involve manipulating the chemistry of the oil and surfactant formulation and are thus low cost due to the low energy input. Current technology illustrates that nanoemulsion size control is relatively straightforward using high energy methods such as high pressure homogenization. Injecting incompressible fluids into a reservoir requires substantial energy in the form of pumps. Incorporating a homogenizer in the injection scheme gives an opportunity for the homogenizer to utilize the high energy inherent in the injection process. This is illustrated using the mechanical energy balance that combines the potential, kinetic, friction, and homogenizer pressure drops inherent in the incorporation of a homogenizer in the injection of nanoemulsions. Analysis shows the relative contributions of each of these pressure effects in the overall determination of the bottom hole injection pressure. Incorporating a homogenizer into a nanoemulsion EOR process would schematically give direct control over nanoemulsion size while conserving energy by using the high energy inherent in an EOR injection process. This would be a novel direct approach of controlling the stability of nanoemulsions (by controlling the size) while not producing extra costs associated with high energy nanoemulsion creation methods. The describe procedure illustrates how to design an injection performance curve that can schematically give control of nanoemulsion size.

Co-optimization of CO2-EOR and Storage Processes under Geological Uncertainty

This paper presents an integrated numerical framework to co-optimize EOR and CO2 storage performance in the Farnsworth field unit (FWU), Ochiltree County, Texas. The framework includes a field-scale compositional reservoir flow model, an uncertainty quantification model and a neural network optimization process. The reservoir flow model has been constructed based on the field geophysical, geological, and engineering data. A laboratory fluid analysis was tuned to an equation of state and subsequently used to predict the thermodynamic minimum miscible pressure (MMP).A history match of primary and secondary recovery processes was conducted to estimate the reservoir and multiphase flow parameters as the baseline case for analyzing the effect of recycling produced gas, infill drilling and water alternating gas (WAG) cycles on oil recovery and CO2 storage. A multi-objective optimization model was defined for maximizing both oil recovery and CO2 storage. The uncertainty quantification model comprising the Latin Hypercube sampling, Monte Carlo simulation, and sensitivity analysis, was used to study the effects of uncertain variables on the defined objective functions. Uncertain variables such as bottom hole injection pressure, WAG cycle, injection and production group rates, and gas-oil ratio among others were selected. The most significant variables were selected as control variables to be used for the optimization process. A neural network optimization algorithm was utilized to optimize the objective function both with and without geological uncertainty. The vertical permeability anisotropy (Kv/Kh) was selected as one of the uncertain parameters in the optimization process.The simulation results were compared to a scenario baseline case that predicted CO2 storage of 74%. The results showed an improved approach for optimizing oil recovery and CO2 storage in the FWU. The optimization process predicted more than 94% of CO2 storage and most importantly about 28% of incremental oil recovery. The sensitivity analysis reduced the number of control variables to decrease computational time. A risk aversion factor was used to represent results at various confidence levels to assist management in the decision-making process. The defined objective functions were proved to be a robust approach to co-optimize oil recovery and CO2 storage. The Farnsworth CO2 project will serve as a benchmark for future CO2–EOR or CCUS projects in the Anadarko basin or geologically similar basins throughout the world.

Optimum design of CO2 storage and oil recovery under geological uncertainty

This paper presents an integrated numerical framework to co-optimize EOR and CO2 storage performance under uncertainty in the Farnsworth Unit (FWU) oil field in Ochiltree County, Texas. The framework includes a field-scale compositional reservoir multiphase flow model, an uncertainty quantification model and a neural network optimization process. The reservoir flow model has been constructed based on the field geophysical, geological, and engineering data. Equation of state parameters were tuned to achieve field measured fluid properties and subsequently used to predict the minimum miscible pressure (MMP).A history match of primary and secondary recovery processes was conducted to estimate the reservoir and multiphase flow parameters as the base case for analyzing the effect of recycling produced gas, infill drilling and water alternating gas (WAG) cycles on oil recovery and CO2 storage. A multi-objective optimization model was defined for maximizing both oil recovery and CO2 storage. The uncertainty quantification model comprising the Latin Hypercube sampling, Monte Carlo simulation, and sensitivity analysis, was used to study the effects of uncertain variables on the defined objective functions. Uncertain variables include bottom hole injection pressure, WAG cycle, injection and production group rates, and gas-oil ratio. The most significant variables were chosen as control variables to be used for the optimization process. A neural network optimization algorithm was utilized to optimize the objective function both with and without geological uncertainty. The vertical permeability anisotropy (Kv/Kh) was selected as one of the uncertain parameters in the optimization process.The simulation results were compared to a scenario baseline case that predicted CO2 storage of 74%. The results showed an improved approach for optimizing oil recovery and CO2 storage in the FWU. The optimization model predicted that about 94% of CO2 would be stored and most importantly, that this increased storage could result in about 25% of incremental oil recovery. The sensitivity analysis reduced the number of control variables to decrease computational time. A risk aversion factor was used to represent results at various confidence levels to assist management in the decision-making process. The defined objective functions were shown to be a robust approach to co-optimize oil recovery and CO2 storage.

Preliminary Study of the Carbon Sequestration and Enhanced Coal Bed Methane Production Potential of Subbituminous to High-Volatile Bituminous Coals of the Healy Creek Formation, Nenana Basin, Interior Alaska

Naturally fractured, unmineable coal seam reservoirs are attractive targets for geological sequestration of carbon dioxide (CO2) because of their high CO2 adsorption capacity and possible cost offsets from enhanced coal bed methane production. In this study, we have investigated the CO2 sequestration and coal bed methane (CH4) production potential of the subbituminous to high-volatile C bituminous Healy Creek Formation coals through preliminary sensitivity analyses, experimental design methods, and fluid flow simulations. The sensitivity analyses indicate that the total volumes of CO2 sequestered and CH4 produced from the Healy Creek coals are mostly sensitive to bottom-hole injection pressure, coal matrix porosity, fracture porosity, fracture permeability, coal compressibility, and coal volumetric strain. The results of the Plackett–Burman experimental design were used to further generate proxy models for probabilistic reservoir forecasts. The probabilistic estimates for the mature, subbituminous to high-volatile C bituminous Healy Creek coals in the entire Nenana Basin indicate that it is possible to sequester between 0.41 trillion cubic feet (TCF) (P10) and 0.05 TCF (P90) of CO2 while producing between 0.36 TCF (P10) and 0.05 TCF (P90) of CH4 at the end of 44-year forecast. Fluid flow scenarios show that CO2 sequestration through a primary reservoir depletion method is the most effective way to inject CO2 in the coals of the Nenana Basin. Including a horizontal well instead of the vertical well resulted in relatively high average gas production rates and subsequent total cumulative gas production. The CO2 buoyancy scenario suggests that the effect of CO2 buoyancy and the nature of caprock should be considered in identifying potential geologic sites for CO2 sequestration.

Coupled solid and fluid mechanics simulation for estimating optimum injection pressure during reservoir CO2-EOR

Reservoir geomechanics can play an important role in hydrocarbon recovery mechanism. In CO2-EOR process, reservoir geomechanics analysis is concerned with the simultaneous study of fluid flow and the mechanical response of the reservoir under CO2 injection. Accurate prediction of geomechanical effects during CO2 injection will assist in modeling the Carbon dioxide recovery process and making a better design of process and production equipment. This paper deals with the implementation of a program (FORTRAN 90 interface code), which was developed to couple conventional reservoir (ECLIPSE) and geomechanical (ABAQUS) simulators, using a partial coupling algorithm. A geomechanics reservoir partially coupled approach is presented that allows to iteratively take the impact of geomechanics into account in the fluid flow calculations and therefore performs a better prediction of the process. The proposed approach is illustrated on a realistic field case. The reservoir geomechanics coupled models show that in the case of lower maximum bottom hole injection pressure, the cumulative oil production is more than other scenarios. Moreover at the high injection pressures, the production rates will not change with the injection bottom hole pressure variations. Also the FEM analysis of the reservoir showed that at CO2 injection pressure of 11000 Psi the plastic strain has been occurred in the some parts of the reservoir and the related stress path show a critical behavior.

Modeling and simulation of carbon sequestration at Cranfield incorporating new physical models

Numerous experimental and field-demonstration tests have been conducted to investigate the feasibility of large-scale long-term storage of CO2 in subsurface formations and to monitor the fate of the injected gas. The Cranfield reservoir in western Mississippi is the location of an injection test and monitoring program conducted by The University of Texas at Austin, Bureau of Economic Geology. Geological carbon sequestration involves injecting CO2 into subsurface formations and storing it using several chemical, physical, and geological mechanisms. CO2 behavior in the subsurface results from the interplay of multiphase flow, fluid-phase behavior, relative permeability, wettability, and gravity. This paper presents findings of a research numerical simulator for modeling CO2 injection at Cranfield. Simulations focusing on a future postinjection period were carried out with sensitivities to uncertain parameters, i.e., relative permeability and its variations due to interfacial tension and buoyancy. Numerical results were consistent with bottom-hole injection flowing pressure for the first 350 days prior to the rate increase and also observed-CO2 breakthrough time at the first observation well. Results also illustrate the importance of using accurate trapping models to predict CO2 immobilization behavior. The impact of CO2/brine relative-permeability curves and trapping model on bottom-hole injection pressure was also demonstrated.

Rapid Pressure Support for Champion SE Reservoirs by Multilayer Fractured Water Injection

Summary The Champion field is a large oil field offshore Negara Brunei Darussalam. This paper discusses the (for us) novel application of water injection-induced multilayer fractured injection into three shallow reservoirs in the Champion Southeast (CPSE) field. Fractured water injection means that the bottomhole injection pressure is allowed to exceed the formation's fracture pressure. Thereby an unpropped fracture is created, which propagates depending on the injection water's leakoff rate into the formation. The project is part of a larger secondary recovery implementation scheme and future efforts to increase economic oil production and ultimate recovery in the whole Champion field. The main boundary condition for the rapid water injection project is the use of existing infrastructure with the exception of three new water pipelines and nine new wells. This paper describes the following: Reservoir setting and production history. Water injection philosophy. Design considerations for fractured water injection including: Pressure requirement to design for fractured water injection. Simulation of fracture growth and containment and resulting conclusions. Design considerations for the multilayer fractured water injector wells including: Selected drilling aspects (well trajectory, drill-in fluid, formation evaluation, casing scheme). Completion design considerations (cleanout, perforating, sand control, selectivity, "smartness", other). Material selection. One of the main conclusions is that fracture growth and containment is not a major issue in soft, high-permeable formations. The main challenge is in drilling the—in some cases—demanding well trajectories and running the "smart" completions in these wells with small tolerances.

Steam-Foam Mechanistic Field Trial in the Midway-Sunset Field

Summary A one-pattern, steam-foam mechanistic field trial was conducted in Section 26C of the Midway-Sunset field (upper Monarch sand). The test objectives were (1) to understand the mechanisms of steam diversion caused by foam under reservoir conditions, (2) to establish whether foam can exist in-depth away from the injection well, and (3) to measure incremental oil that can be attributed to foam. Surfactant was injected with steam and nitrogen continuously, and bottom-hole injection pressure (BIHP) increased from 100 to 300 psig, indicating good foam generation. Better steam distribution across the injector's perforations occurred when foam was generated. Improvements in both vertical and areal sweep efficiency of steam were observed. Substantial temperature and gas saturation increases coincided with surfactant breakthrough and local reservoir pressure increases at observation wells. Complementary laboratory core-floods showed that foam generation could occur at low-pressure gradients, which are typical of in-depth conditions. Both laboratory and field data were interpreted as evidence that the in-depth presence of foam was the result of local generation wherever surfactant, steam, and nitrogen were present, rather than propagation of a foam bank generated near the injector. Some oil-production increase was also observed during the test; however, an accurate quantitative estimate of incremental oil owing to foam was difficult to establish.

Fracturing Gradients in Waterfloods of Low-Permeability, Partially Depleted Zones

Fracturing during waterflooding can be diagnosed from pressure fall-off and step-rate injectivity test data. In tectonically relaxed zones these well test data also yield Poisson ratio. Information given here suggests that Poisson ratios ranging from 0.23 to 0.33 are normal for low-permeability Poisson ratios ranging from 0.23 to 0.33 are normal for low-permeability rocks, and that higher ratios may indicate fracturing through shaly cap rock. Introduction Formation fracturing, or "pressure parting" as it is sometimes called, can occur at surprisingly low pressure gradients during water injection. For conditions pressure gradients during water injection. For conditions conducive to vertical fracturing these fracturing gradients expressed as bottom-hole injection pressure vs depth may be as low as 0.50 psi/ft. This is much lower than the gradients usually observed in the same fields when wells are hydraulically fractured during initial completions. The reason for this difference is that the fracturing gradient is dependent on formation pressure. While the formation pressure is high, the fracturing gradient observed in completion work will also be high, but as the pressure declines during primary production, the fracturing gradient likewise primary production, the fracturing gradient likewise declines. Field Observations Fracturing gradients of 0.57 psi/ft were reported by Eaton for a pressure-depleted West Texas field where old producing wells had been converted to water injection wells. In the same field, gradients equalled 0.68 to 0.70 psi/ft during hydraulic fracturing of new wells. Eaton also reported fracturing gradients equal to 0.748, 0.864, and 0.993 psi/ft after successive 6-month periods in a California injection well, with the changes being attributed to gradual increases in formation pressure around the. wellbore. Heck also made reference to similar observations in the Bradford, Pa., field. These, and similar literature references, illustrate the phenomenon in a qualitative manner, but not enough data are given for quantitative correlations. To fill this lack of correlative data, we observed fracture gradients and also obtained corresponding shut-in formation pressures; the latter values we determined from pressure fall-off tests, using the method of Hazebroek et al. One such set of data was obtained in Field A, a 6,500-ft deep Mississippian limestone reef reservoir. in this reservoir the average fracturing gradient was reported as 0.78 psi/ft at a discovery pressure of about 2,675 psig. During primary production the formation pressure declined to values ranging from 780 to 1,700 psi in the wells of interest (the large range of values being the consequence of permeability barriers throughout the reservoir). permeability barriers throughout the reservoir). Approximately a month after old producers in this reservoir were converted to injection wells, fracture gradients and shut-in formation pressures were observed in five wells. This was repeated after another 5 months of water injection. It may be seen from the data in Fig. 1 that during the period of observation the shut-in formation pressure in the injection wells increased, on the average, 750 psi. This was accompanied by a definite rise in the fracturing gradients, as evidenced by the fact that fracture gradients averaged 0.55 psi/ft in the first month and 0.65 psi/ft in the sixth month of injection. JPT P. 727

Theoretical size of hydraulically induced horizontal fractures and corresponding surface uplift in an idealized medium

For the disposal of radioactive wastes by hydraulic fracturing and grout injection, it is considered essential that the induced fractures be nearly horizontal. Bottom-hole injection pressure in excess of overburden pressure has been recognized as one indication that fracturing is horizontal. The amount of uplift of the ground surface caused by the injection can be used as another indicator. For an impervious, homogeneous, isotropic medium, a mathematical model for calculating the amount of uplift of the ground surface, the maximum separation of the horizontally induced fracture at the injection well site, and the radius of extension of the fracture was developed from the basic formulas derived by I.N. Sneddon (1946) and A.E. Green (1949). If the bottom-hole injection pressure is greater than the overburden pressure, and the observed uplift is nearly the same as the calculated uplift, the fracture orientation probably is nearly horizontal. Uplifts from 9 injections made at the Oak Ridge National Laboratory, Tennessee, from 1960 through 1965, have been used to test the validity of the mathematical model. The calculations agree reasonably well with the observed data. (31 refs.)

The Cutting Carrying Capacity of Air at Pressures Above Atmospheric

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 180–185. Abstract The turbulent flow drag coefficients, or friction factors, have been experimentally determined for the cuttings normally encountered in drilling operations. The gas law and average drag coefficients for characteristically flat particles (limestones and shales) and for angular to sub-rounded particles (sandstones) were used to extend Newton's equation to a more useful form. The resulting equations are expressions for the slip velocity of a particle as a function of the particle size and shape, the bottom-hole injection pressure, and the bottom-hole temperature. The velocities necessary to lift actual rock cuttings as observed in the laboratory were compared with velocities predicted from the derived equations. Results indicate that there is no single correct circulating velocity and that the commonly used 3,000 ft/min linear velocity may be sufficient to lift only very small particles. Introduction A promising departure from rotary hydraulic drilling is air or gas drilling. In many instances the rate of penetration and bit life increases resulting from this method have been very substantial. Further the application of air drilling in areas of lost circulation or water sensitive pay zones has been highly successful. Purpose For the drilling contractor, the practical question remains, "How much air pressure and volume should I have?" It is necessary to have a reasonable knowledge of the air velocities and pressures required in air drilling operations for the proper design and most advantageous use of surface equipment and for adequate removal of cuttings from the borehole. Based on experience, most operators agree that at least 3,000 ft/min linear velocity is necessary for satisfactory hole cleaning. It was the purpose of this investigation to evaluate the drag coefficients, or friction factors, for the cuttings normally encountered in drilling operations, i.e., sandstones, limestones and shales, and to utilize the values obtained to develop an expression for the minimum velocities and pressures (hence the volumes) necessary to lift these cuttings.