drilling formulas mud pump output made in china

Rig pump output, normally in volume per stroke, of mud pumps on the rig is  one of important figures that we really need to know because we will use pump out put figures to calculate many parameters such as bottom up strokes,  wash out depth, tracking drilling fluid, etc. In this post, you will learn how to calculate pump out put for triplex pump and duplex pump in bothOilfield and Metric Unit.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Positive displacements pumps are generally used on drilling rigs to pump high pressure and high volume of drilling fluids throughout a drilling system. There are several reasons why the positive displacement mud pumps are used on the rigs.

The duplex pumps (Figure 1) have two cylinders with double acting. It means that pistons move back and take in drilling mud through open intake valve and other sides of the same pistons, the pistons push mud out through the discharge valves.

When the piston rod is moved forward, one of intake valves is lift to allow fluid to come in and one of the discharge valve is pushed up therefore the drilling mud is pumped out of the pump (Figure 2).

On the other hand, when the piston rod is moved backward drilling fluid is still pumped. The other intake and discharge valve will be opened (Figure 3).

The triplex pumps have three cylinders with single acting. The pistons are moved back and pull in drilling mud through open intake valves. When the pistons are moved forward and the drilling fluid is pushed out through open discharge valves.

On the contrary when the piston rods are moved backward, the intake valve are opened allowing drilling fluid coming into the pump (Figure 6). This video below shows how a triplex mud pump works.

Because each pump has power rating limit as 1600 hp, this will limit capability of pump. It means that you cannot pump at high rate and high pressure over what the pump can do. Use of a small liner will increase discharge pressure however the flow rate is reduces. Conversely, if a bigger liner is used to deliver more flow rate, maximum pump pressure will decrease.

As you can see, you can have 7500 psi with 4.5” liner but the maximum flow rate is only 297 GPM. If the biggest size of liner (7.25”) is used, the pump pressure is only 3200 psi.

Finally, we hope that this article would give you more understanding about the general idea of drilling mud pumps. Please feel free to add more comments.

Positive displacements pumps are generally used on drilling rigs to pump high pressure and high volume of drilling fluids throughout a drilling system. There are several reasons why the positive displacement mud pumps are used on the rigs.

The duplex pumps (Figure 1) have two cylinders with double acting. It means that pistons move back and take in drilling mud through open intake valve and other sides of the same pistons, the pistons push mud out through the discharge valves.

When the piston rod is moved forward, one of intake valves is lift to allow fluid to come in and one of the discharge valve is pushed up therefore the drilling mud is pumped out of the pump (Figure 2).

On the other hand, when the piston rod is moved backward drilling fluid is still pumped. The other intake and discharge valve will be opened (Figure 3).

The triplex pumps have three cylinders with single acting. The pistons are moved back and pull in drilling mud through open intake valves. When the pistons are moved forward and the drilling fluid is pushed out through open discharge valves.

On the contrary when the piston rods are moved backward, the intake valve are opened allowing drilling fluid coming into the pump (Figure 6). This video below shows how a triplex mud pump works.

Because each pump has power rating limit as 1600 hp, this will limit capability of pump. It means that you cannot pump at high rate and high pressure over what the pump can do. Use of a small liner will increase discharge pressure however the flow rate is reduces. Conversely, if a bigger liner is used to deliver more flow rate, maximum pump pressure will decrease.

As you can see, you can have 7500 psi with 4.5” liner but the maximum flow rate is only 297 GPM. If the biggest size of liner (7.25”) is used, the pump pressure is only 3200 psi.

Finally, we hope that this article would give you more understanding about the general idea of drilling mud pumps. Please feel free to add more comments.

In geotechnical engineering, drilling fluid, also called drilling mud, is used to aid the drilling of boreholes into the earth. Often used while drilling oil and natural gas wells and on exploration drilling rigs, drilling fluids are also used for much simpler boreholes, such as water wells. One of the functions of drilling mud is to carry cuttings out of the hole.

The three main categories of drilling fluids are water-based muds (WBs), which can be dispersed and non-dispersed; non-aqueous muds, usually called oil-based muds (OBs); and gaseous drilling fluid, in which a wide range of gases can be used. Along with their formatives, these are used along with appropriate polymer and clay additives for drilling various oil and gas formations.

The main functions of drilling fluids include providing hydrostatic pressure to prevent formation fluids from entering into the well bore, keeping the drill bit cool and clean during drilling, carrying out drill cuttings, and suspending the drill cuttings while drilling is paused and when the drilling assembly is brought in and out of the hole. The drilling fluid used for a particular job is selected to avoid formation damage and to limit corrosion.

Many types of drilling fluids are used on a day-to-day basis. Some wells require different types to be used in different parts of the hole, or that some types be used in combination with others. The various types of fluid generally fall into broad categories:

Water-based mud (WBM): Most water-based mud systems begin with water, then clays and other chemicals are added to create a homogeneous blend with viscosity between chocolate milk and a malt. The clay is usually a combination of native clays that are suspended in the fluid while drilling, or specific types of clay processed and sold as additives for the WBM system. The most common type is bentonite, called "gel" in the oilfield. The name likely refers to the fluid viscosity as very thin and free-flowing (like chocolate milk) while being pumped, but when pumping is stopped, the static fluid congeals to a "gel" that resists flow. When adequate pumping force is applied to "break the gel," flow resumes and the fluid returns to its free-flowing state. Many other chemicals (e.g. potassium formate) are added to a WBM system to achieve desired effects, including: viscosity control, shale stability, enhance drilling rate of penetration, and cooling and lubricating of equipment.

Oil-based mud (OBM): Oil-based mud has a petroleum based fluid such as diesel fuel. Oil-based muds are used for increased lubricity, enhanced shale inhibition, and greater cleaning abilities with less viscosity. Oil-based muds also withstand greater heat without breaking down. The use of oil-based muds has special considerations of cost, environmental concerns such as disposal of cuttings in an appropriate place, and the exploratory disadvantages of using oil-based mud, especially in wildcat wells. Using an oil-based mud interferes with the geochemical analysis of cuttings and cores and with the determination of API gravity because the base fluid cannot be distinguished from oil that is returned from the formation.

Synthetic-based fluid (SBM) (Otherwise known as Low Toxicity Oil Based Mud or LTOBM): Synthetic-based fluid is a mud in which the base fluid is a synthetic oil. This is most often used on offshore rigs because it has the properties of an oil-based mud, but the toxicity of the fluid fumes are much less. This is important when the drilling crew works with the fluid in an enclosed space such as an offshore drilling rig. Synthetic-based fluid poses the same environmental and analysis problems as oil-based fluid.

On a drilling rig, mud is pumped from the casing, where it emerges from the top. Cuttings are then filtered out with either a shale shaker or the newer shale conveyor technology, and the mud returns to the mud pits. The mud pits allow the drilled "fines" to settle and the mud to be treated by adding chemicals and other substances.

The returning mud may contain natural gases or other flammable materials which will collect in and around the shale shaker / conveyor area or in other work areas. Because of the risk of a fire or an explosion if they ignite, special monitoring sensors and explosion-proof certified equipment is commonly installed, and workers are trained in safety precautions. The mud is then pumped back down the hole and further re-circulated. After testing, the mud is treated periodically in the mud pits to ensure it has desired properties that optimize and improve drilling efficiency and borehole stability.

Drilling fluid carries the rock excavated by the drill bit up to the surface. Its ability to do so depends on cutting size, shape, and density, and speed of fluid traveling up the well (annular velocity). These considerations are analogous to the ability of a stream to carry sediment. Large sand grains in a slow-moving stream settle to the stream bed, while small sand grains in a fast-moving stream are carried along with the water. The mud viscosity is an important property, as cuttings will settle to the bottom of the well if the viscosity is too low.

Most drilling muds are thixotropic (viscosity increases when static). This characteristic keeps the cuttings suspended when the mud is not flowing during, for example, maintenance.

High density fluids may clean holes adequately even with lower annular velocities (by increasing the buoyancy force acting on cuttings) but may have a negative impact if mud weight exceeds that needed to balance the pressure of surrounding rock (formation pressure), so mud weight is not usually increased for hole cleaning.

For effective solids controls, drill solids must be removed from mud on the 1st circulation from the well. If re-circulated, cuttings break into smaller pieces and are more difficult to remove.

If formation pressure increases, mud density should be increased to balance pressure and keep the wellbore stable. The most common weighting material is baryte. Unbalanced formation pressure will cause an unexpected influx (also known as a kick) of formation fluids into the wellbore possibly leading to a blowout from pressurized formation fluid.

Hydrostatic pressure = density of drilling fluid * true vertical depth * acceleration of gravity. If hydrostatic pressure is greater than or equal to formation pressure, formation fluid will not flow into the wellbore.

In practice, mud density should be limited to the minimum necessary for well control and wellbore stability. If too great it may fracture the formation.

Mud column pressure must exceed formation pressure, in this condition mud filtrate invades the formation, and a filter cake of mud is deposited on the wellbore wall.

Depending on the mud system in use, a number of additives can improve the filter cake (e.g. bentonite, natural & synthetic polymer, asphalt and gilsonite).

Chemical composition and mud properties must combine to provide a stable wellbore. Weight of the mud must be within the necessary range to balance the mechanical forces.

In shales, mud weight is usually sufficient to balance formation stress, as these wells are usually stable. With water base mud, chemical differences can cause interactions between mud & shale that lead to softening of the native rock. Highly fractured, dry, brittle shales can be extremely unstable (leading to mechanical problems).

Various chemical inhibitors can control mud / shale interactions (calcium, potassium, salt, polymers, asphalt, glycols and oil – best for water sensitive formations)

To add inhibition, emulsified brine phase (calcium chloride) drilling fluids are used to reduce water activity and creates osmotic forces to prevent adsorption of water by Shales.

Lubrication based on the coefficient of friction.("Coefficient of friction" is how much friction on side of wellbore and collar size or drill pipe size to pull stuck pipe) Oil- and synthetic-based mud generally lubricate better than water-based mud (but the latter can be improved by the addition of lubricants).

Drilling fluids also support portion of drill-string or casing through buoyancy. Suspend in drilling fluid, buoyed by force equal to weight (or density) of mud, so reducing hook load at derrick.

Hydraulic energy provides power to mud motor for bit rotation and for MWD (measurement while drilling) and LWD (logging while drilling) tools. Hydraulic programs base on bit nozzles sizing for available mud pump horsepower to optimize jet impact at bottom well.

Mud loggers examine cuttings for mineral composition, visual sign of hydrocarbons and recorded mud logs of lithology, ROP, gas detection or geological parameters.

Mud should have thin, slick filter cake, with minimal solids in filter cake, wellbore with minimal cuttings, caving or bridges will prevent a good casing run to bottom. Circulate well bore until clean.

Mud low viscosity, mud parameters should be tolerant of formations being drilled, and drilling fluid composition, turbulent flow - low viscosity high pump rate, laminar flow - high viscosity, high pump rate.

Water based drilling fluid has very little toxicity, made from water, bentonite and baryte, all clay from mining operations, usually found in Wyoming and in Lunde, Telemark.

There are specific chemicals that can be used in water based drilling fluids that alone can be corrosive and toxic, such as hydrochloric acid. However,

Caustic (sodium hydroxide), anhydrous lime, soda ash, bentonite, baryte and polymers are the most common chemicals used in water based drilling fluids.

Water-based drilling mud most commonly consists of bentonite clay (gel) with additives such as barium sulfate (baryte), calcium carbonate (chalk) or hematite. Various thickeners are used to influence the viscosity of the fluid, e.g. xanthan gum, guar gum, glycol, carboxymethylcellulose, polyanionic cellulose (PAC), or starch. In turn, deflocculants are used to reduce viscosity of clay-based muds; anionic polyelectrolytes (e.g. acrylates, polyphosphates, lignosulfonates (Lig) or tannic acid derivates such as Quebracho) are frequently used. Red mud was the name for a Quebracho-based mixture, named after the color of the red tannic acid salts; it was commonly used in the 1940s to 1950s, then was made obsolete when lignosulfonates became available. Other components are added to provide various specific functional characteristics as listed above. Some other common additives include lubricants, shale inhibitors, fluid loss additives (to control loss of drilling fluids into permeable formations). A weighting agent such as baryte is added to increase the overall density of the drilling fluid so that sufficient bottom hole pressure can be maintained thereby preventing an unwanted (and often dangerous) influx of formation fluids

Freshwater mud: Low pH mud (7.0–9.5) that includes spud, bentonite, natural, phosphate treated muds, organic mud and organic colloid treated mud. high pH mud example alkaline tannate treated muds are above 9.5 in pH.

Water based drilling mud that represses hydration and dispersion of clay – There are 4 types: high pH lime muds, low pH gypsum, seawater and saturated salt water muds.

Low solids mud: These muds contain less than 3–6% solids by volume and weight less than 9.5 lbs/gal. Most muds of this type are water-based with varying quantities of bentonite and a polymer.

Oil based mud: Oil based muds contain oil as the continuous phase and water as a contaminant, and not an element in the design of the mud. They typically contain less than 5% (by volume) water. Oil-based muds are usually a mixture of diesel fuel and asphalt, however can be based on produced crude oil and mud

"Mud engineer" is the name given to an oil field service company individual who is charged with maintaining a drilling fluid or completion fluid system on an oil and/or gas drilling rig.mud engineer, or more properly drilling fluids engineer, is critical to the entire drilling operation because even small problems with mud can stop the whole operations on rig. The internationally accepted shift pattern at off-shore drilling operations is personnel (including mud engineers) work on a 28-day shift pattern, where they work for 28 continuous days and rest the following 28 days. In Europe this is more commonly a 21-day shift pattern.

In offshore drilling, with new technology and high total day costs, wells are being drilled extremely fast. Having two mud engineers makes economic sense to prevent down time due to drilling fluid difficulties. Two mud engineers also reduce insurance costs to oil companies for environmental damage that oil companies are responsible for during drilling and production. A senior mud engineer typically works in the day, and a junior mud engineer at night.

The cost of the drilling fluid is typically about 10% (may vary greatly) of the total cost of drilling a well, and demands competent mud engineers. Large cost savings result when the mud engineer and fluid performs adequately.

The compliance engineer is the most common name for a relatively new position in the oil field, emerging around 2002 due to new environmental regulations on synthetic mud in the United States. Previously, synthetic mud was regulated the same as water-based mud and could be disposed of in offshore waters due to low toxicity to marine organisms. New regulations restrict the amount of synthetic oil that can be discharged. These new regulations created a significant burden in the form of tests needed to determine the "ROC" or retention on cuttings, sampling to determine the percentage of crude oil in the drilling mud, and extensive documentation. No type of oil/synthetic based mud (or drilled cuttings contaminated with OBM/SBM) may be dumped in the North Sea. Contaminated mud must either be shipped back to shore in skips or processed on the rigs.

Clark, Peter E. (1995-01-01). "Drilling Mud Rheology and the API Recommended Measurements". SPE Production Operations Symposium. Society of Petroleum Engineers. doi:10.2118/29543-MS. ISBN 9781555634483.

Mr. Carter has over fifty five years" experience in domestic and international engineering and management positions in the area of drilling, completion and E&P waste management with Conoco, Baroid, and several other drilling contractors. He has conducted seminars and schools on fluids, rig equipment, and drilling engineering related subjects associated with drilling optimization, cost reduction, and well control. Tom has served as Chairman of the API standardization committee (SC 13) on Drilling and Completion Fluid Materials. He was a SPE Distinguished Lecturer in 1993 and served as the Editor of the SPE reprint series book on drilling fluids. Currently, he is a member of the Chevron Clear Leader Center serving as a Technical Learning Advisor in Houston. He coordinates and has teaching participation in several subject areas such as Coiled Tubing Operations, Directional Drilling, Drilling Fluids, Drilling Practices, Fundamentals for Drilling and Completion, HPHT Drilling and Completions, and Solids Control and Waste Management. He is still active in several industry organizations and was President of the Houston chapter of the American Association of Drilling Engineers, Coordinator for the SPE North American Forum Series, Membership Chairman of the editorial committee for the Journal of Petroleum Technology and on the Board of Directors for the Ocean Energy Center Society (Ocean Star rig museum in Galveston). He has published 20 technical publications and holds five U.S. patents. He graduated with a BS in Geology from Centenary College in Shreveport, Louisiana in 1963.

Multilateral-horizontal-well drilling is an efficient approach for stimulating shallow, low-permeability, marginal, and coalbed-methane (CBM) reservoirs. Radial-jet-drilling (RJD) technology, which uses a high-pressure water jet, aims to drill tens of laterals from a vertical wellbore. Hydraulics design is essential for successful field-drilling operations. However, detailed hydraulics calculations and design methods have not yet been published.

The hydraulics calculations corresponded well with the field data. The model error was within 8%. The pressure loss of the high-pressure hose and jet bit represents a large proportion of the RJD-system pressure loss (41.2 and 55.8%, respectively). According to the operation profile, the calculated pump pressure will help the field engineer to estimate the working status of downhole tools. The results show that the pump flow rate should be optimized for different well configurations. The optimum flow-rate range was determined by the minimum lateral-extending force, minimum rock-breaking jet-bit-pressure drop, and minimum equipment-safety working pressure. To maximize the rate of penetration (ROP), the largest flow rate within that interval was selected as the optimum flow rate. A flow rate of 57.24 L/min was optimal for the case well.

70% of the earth is covered by sea. In the future, 40% of global gas-and-oil reserves are projected to come from deepwater; moreover, the foreseeable alternative energy “natural gas hydrate” mainly originates from deepwater as well. Consequently, deepwater study has become a Frontier field to explore essential scientific problems such as the origins of multicellular life, evolution of the earth, and climate change. Offshore drilling is the most intuitive approach to acquiring subsea stratigraphic information, which is also a leading method of marine resource exploration.

In Offshore drilling, the drilling equipment must meet high safety and reliability because it can withstand the effects of wind, wave and current, gas hydrate, strong tropical storm and the corrosion damage of marine environment to the equipment. At present, two mature deepwater drilling units have been developed: deepwater drilling ship and deepwater semi submersible drilling platform [1, 2]. Drilling ship is one of the most mobile drilling units. It has the advantages of flexible movement, simple berthing and wide range of water depth, and is especially suitable for drilling in deep water or deeper water. Drilling ships are mainly active in the waters of Brazil, the Gulf of Mexico and West Africa. Since the emergence of semi submersible drilling platform in the 1960s, it has experienced six generations of development. The sixth generation semi submersible drilling platform appeared at the beginning of the 21st century. With dynamic positioning, the hull structure is more optimized and the quality is reduced. It is equipped with automatic control system, with larger variable load, operating water depth of more than 3,000 m, maximum drilling depth of 12,000 m, strong derrick bearing capacity and high power of drilling winch.

With advancements in offshore oil drilling, deepwater drilling technology has been developing consistently, which has promoted the development of conductor jetting, dynamic killing, well logging while-drilling and pressure while-drilling techniques [1]. However, the exploration and development of deepwater resources still suffer from many challenges, which mainly span following three aspects [3–8]. First, if a riser is adopted during operation, riser length must grow with increasing water depth, yielding a heavy and cumbersome structure, especially for the upper riser, which must bear a larger tension. Second, difficulties arise during advancing in the horizontal section; when drilling in the horizontal section, it is difficult for the drilling fluid to carry the rocks. Moreover, the borehole friction increases rapidly, resulting in extra weight constraints. Third, owing to the narrow pore-fraction pressure window, a precise control of wellbore pressure is required for formations with severe leakage, reservoir pressure failure, and high sulfur content. Therefore, focusing on a series of challenges in deepwater drilling, a subsea closed-cycle riserless drilling method with pump + gas combined lift is proposed in this study, providing the theoretical foundation and design basis for efficient, economical, and safe subsea drilling applications.

In this work, the advantages of closed-cycle riserless drilling method using a pump + gas combined lift are analyzed and its multiphase flow drilling model is proposed. By solving the model, the influence of drilling fluid displacement, gas injection displacement, gas injection site and seawater depth on drilling hydraulic parameters can be obtained. The optimization hydraulic parameters design method of closed-cycle riserless drilling method with a subsea pump + gas combined lift is proposed.

In 2001, a Norwegian company called AGR developed a riserless mud recovery (RMR) drilling technology based on its cutting transportation system (CTS). The principle of this technology is to pump mud subsea to the drilling platform by leveraging the mud suction module at the wellhead, subsea mud lifting pump, as well as mud return pipeline, thereby forming a closed-cycle of drilling fluid. The practice costs and risks are significantly lower than that of methods using risers [9]. First, RMR was merely adopted for shoal-water oil-and-gas exploitation, which is mainly targeted to solve the drilling challenges concerning complex subsea conditions and shallow risks and ensures a smooth borehole drilling operation on the surface layer. In 2003, the first commercial RMR application was performed in the Caspian Sea. As the technology developed, the closed-cycle riserless drilling system has been advancing from shallow sea to deep sea applications. The issues restricting the application of deepwater closed-cycle drilling methods with risers mainly stem from the lifting capacity of mud lifting pump and strength of mud return pipeline. Therefore, AGR, together with Shell, BP America, and DEMO2000, formed an industrial project team to develop the so-called deepwater RMR system, and successfully conducted a field test in the South China Sea (Malaysia) at a depth of 1,419 m in September 2008. The test has proved the feasibility of this technology in deepwater drilling applications and its advantages for drilling in the South China Sea, such as safe drilling in strata with shallow risk, overcoming the mud logging restrictions, extending the setting depth of surface casing, etc. In 2008, the RMR drilling system has been adopted for a drilling operation with self-elevating platform for the first time, which achieved favorable results. The deepwater RMR system is illustrated in Figure 1.

Compared with the conventional riserless mud lifting systems, this system has introduced an innovative gas lifting process by adopting a gas + pump combined lifting scheme. This design can effectively decrease the subsea pump working power, enhance the lifting head, reduce the cost and difficulty of construction, improve the reliability of lifting systems, and enable the application of closed-cycle riserless drilling in offshore applications with higher depth. The gas + pump combined lifting system is illustrated in Figure 2.

Major advantages of this novel subsea closed-cycle riserless drilling method with a subsea pump + gas combined lift in deepwater drilling are as follows:

(1) Riserless drilling: Conventional offshore drilling adopts risers to isolate seawater inside the drilling fluid system. The dual-channel drill pipeline exposed to seawater replaces the cumbersome riser system and its components, thereby reducing the amount of drilling fluid and number of drilling pumps required, as well as the bearing capacity and space requirements for drilling rig deck. Moreover, it can reduce the quantity of casing, optimize the structure along well depth, and obtain a wellbore with a single diameter.

(2) Closed-cycle system: When a subsea pump + gas combined lift is used, drilling fluid is pumped to the well bottom through the inner pipe of the drilling pipeline; then, it impacts the rock stratum via jet from the drill bit. The fluid, carrying rock debris cut by the drilling bit, is then lifted to the subsea mud pipeline along the annular channel formed between the wellbore and drilling pipe. Exploiting the drilling fluid return pipeline, rock debris are carried to the drilling platform via the subsea pump + gas combined lift. Closed-cycle serves as the basis for the implementation of deepwater drilling technology with pressure control. Via precise control of bottom hole pressure and drilling fluid flow, this technique can address the narrow safety density window issue in deepwater drilling, while reducing down-time and well control risks.

(3) High cutting carrying efficiency: In conventional offshore drilling applications, the drilling fluid is pumped in via drill pipe and returned through the borehole annulus and riser annulus after carrying the cuttings. By leveraging the subsea pump + gas combined lift, carried drilling fluid cuttings return to the wellhead via the drilling fluid return pipeline. The drilling fluid is not required to be transported at high velocities for carrying cuttings to the wellhead, which reduces the scouring of the borehole wall, which is greatly applicable to wells with large displacement and horizontal wells.

(4) Enlarging the working water depth of third- and fourth-generation drilling rigs: deepwater and ultra-deepwater operations mandate significant load-bearing requirements on drilling rigs and deck space. Hence, for conventional offshore drilling, fifth-, sixth- or seventh-generation drilling rigs are required. The novel closed-cycle riserless drilling method using a subsea pump + gas lift alleviates the load-bearing capacity and space requirements on the drilling rig deck. Consequently, third- and fourth-generation drilling rigs can be adopted for such drilling operations, which reduces the daily running costs of drilling rigs and increases their working water depth.

This technology aims to optimize the hydraulic parameters in deepwater drilling. The hydraulic parameter accuracy directly affects the safety and efficiency of drilling. Significant discrepancies exist between the novel closed-cycle riserless drilling with a subsea pump + gas combined lift and conventional deepwater drilling applications, which are mainly observed in the calculation of gas-liquid-solid three-phase flow in the upper return pipeline, wellbore pressure, and cutting carrying efficiency when subsea pump is online. The wellbore multiphase flow model states the fundamental theory for calculating the hydraulic parameters of the novel closed-cycle riserless drilling with a subsea pump + gas combined lift.

The foremost multiphase flow simulation of the well kick adopts homogeneous flow models. Leblanc and Leuis (1968) established the first multiphase flow model of a well kick suitable for gas overflow [10]. This model assumes that the overflowing gas exists as a continuous column inside the wellbore; then, performs simple calculations regarding the pressure change in the annulus during overflow without considering the mutual slippage between gas and liquid phases. Similarly, based on the concept of homogeneous flow, Horberock and Stanbery (1981) calculated the average value of gas-liquid characteristic parameters [11]; then, they established the continuity and momentum conservation equations of the homogeneous fluid in vertical pipeline. Subsequently, they simulated the pressure change in the wellbore. Santos (1982) established a relatively comprehensive multiphase flow model of deepwater kick by assuming a bubbly status in the wellbore during overflow [12]. In their model, they introduced the void fraction concept, as well as the effects of gas-liquid slippage and friction pressure losses in two-phase flows. Nickens (1987) considered the velocity slippage between different phases as well as the friction pressure loss of single and multiple flows. By numerically solving the dynamic equations of mass conservation for gas and liquid phases simultaneously, a comprehensive multiphase flow model in the wellbore has been established [13]. However, many factors, such as temperature variation, gas dissolution, etc., were not considered in this model. Adopting the established model, the effects of wellbore shape and hydraulic parameters of drilling assembly on the borehole pressure distribution were investigated. Moreover, many scholars, such as White and Walton (1990), Van Slyke and Huang (1990), Szczepanski et al. (1998), Nunes et al. (2002), and Velmurugan et al. (2016), applied the classic model of gas-liquid two-phase flow during well kick to analyze the multiphase flow pattern in the wellbore under different working conditions, namely, varying mud types [14, 15], overflowing gas composition, and deepwater drilling [16–18]. Sun et al. (2017, 2022) integrated the hydrate phase balance equilibrium and phase transition rate models with the multiphase flow model of deepwater well kick [19, 20]. Based on their analysis, they discovered that during well kick, the phase transition of hydrate would lead to concealment in the early stage and burstiness in the later stage. Fu et al. (2020, 2022) revealed that the hydrate formation makes drilling fluid exhibit the shear-thinning at low shear rate condition and the shear-thickening at high shear rate condition. The corresponding rheological model of drilling fluid is developed incorporating hydrate concentration, shear rate and additive concentration, which has an important contribution to improvement of the multiphase flow [21–23].

Because the novel closed-cycle riserless drilling method with a subsea pump + gas combined lift is still in its initial stage globally, current research on the multiphase flow pattern in wellbore is mainly based on the working conditions of deepwater drilling applications with risers. The multiphase flow patterns in wellbore that are affected by multiple factors, such as subsea pump and gas injection, are rarely reported. Hence, the existing theoretical model is difficult to apply in most cases.

When using the novel deepwater closed-cycle riserless drilling with a subsea pump + gas combined lift, gas lifting module enters wellbore through the mud return pipeline and changes the flow patterns of drilling fluid from liquid-solid two-phase flow to complex three-phase flow comprising gas, liquid, and solid. The selection process of pump + gas combined lifting parameters is constrained by various restrictions, such as borehole cleanliness, mud pump capacity, formation stability, rated power of lifting pump, etc. The following requirements should be fulfilled:

The drilling fluid return pipeline is divided into two sections, namely, sections a and b. Along the drilling fluid return pipeline, the section from the subsea lifting pump to the intersection of gas injection pipeline and drilling fluid return pipeline is named section a of the return pipeline (as shown in Figure 2). Accordingly, the section from subsea lifting pump to the intersection of the gas injection pipeline and drilling fluid return pipeline to the drilling ship is named section b of return pipeline. The multiphase flow equations of sections a and b are established. No gas phase exists in section a of drilling fluid return pipeline. By considering only the liquid and cutting phases, the multiphase flow equations in section a of drilling fluid return pipeline are stated as follows:

where A denotes the sectional area of annulus (m2);El and Ec denote the volume fraction of drilling fluid and cutting phases, respectively (dimensionless); vc and vl denote the velocity of cutting and drilling fluid phases (m/s); ρc and ρl denote the density of cutting and drilling fluid phases, respectively, (kg/m3); qc denotes the generation rate of cuttings (kg/s); fr denotes the on-way friction pressure drop (Pa); s is the coordinate along the flow direction (m); α is the deviation angle of the well (°); p denotes the pressure (Pa); Ta is fluid temperature in the drilling fluid return pipeline (°C); ke is the thermal conductivity of seawater (W/(m°C)); rco is the outer diameter of drilling fluid return pipeline (m); wc is the mass flow rate of cuttings (kg/s); wl is the mass flow of drilling fluid (kg/s); Cpg is the specific heat of gas phase (J/kg°C); Tei and Tt denote the temperatures of seawater and drilling fluid, respectively, in return pipeline (°C); Ua is the total heat transfer coefficient between fluid in drilling fluid return pipeline and seawater (W/(m2·°C)); TD is the transient heat transfer coefficient; g is the gravitational acceleration (m/s2); h is the well depth at a certain point (m); A′ is an intermediate parameter.

The gas lifting system injects gas into the drilling fluid return pipeline, which alters the flow characteristics of drilling fluid from the original liquid-solid two-phase flow to the more complex gas-liquid-solid three-phase flow. Consequently, the multiphase flow equations in section b of drilling fluid return pipeline are stated as follows:

To solve control equations of multiphase flow, it is necessary to combine the calculation equations of gas phase volume fraction, drilling fluid rheology, distribution coefficient, and drift velocity[19].

The gas phase volume fraction, Eg, is calculated using Eq. 11; gas distribution coefficient, C0, is calculated using Eq. 12; drift velocity, Vgr, is calculated using Eq. 13; rheological properties of drilling fluid in the pipeline are calculated using Eq. 13, including the apparent viscosity, plastic viscosity, and dynamic shear force of the drilling fluid: Eq. 14

where Vsg denotes the apparent flow velocity of gas (m/s); Vm denotes the mixing flow velocity of drilling fluid and cuttings (m/s); σ is the surface tension (Pa); C0 is the distribution coefficient (dimensionless); D0 is the pipe diameter (m); Retp is the two-phase Reynolds number (dimensionless); θ is the average sectional void fraction (dimensionless); f (p,T) represents μa (p,T), μp (p,T), and τa (p,T), respectively, namely, apparent viscosity, plastic viscosity, and dynamic shear force under pressure p and temperature T; p0 is the atmospheric pressure (MPa); T0 is the ambient temperature (°C); A, B, C, and D denote the characteristic constants of drilling fluid, whose values are related to the composition of drilling fluid.

where k1, k2, and k3 are experimental coefficients, whose values are 0.3268, 0.07068, and 0.0813, respectively; NR is the sinking Reynolds number of particles; μe is the plastic viscosity of drilling fluid (mPa·s); ρf and ρs are the density of drilling fluid and cuttings, respectively (g/cm3).

The temperature and pressure of drilling fluid inside the return pipeline on sea surface are measured using thermometer and pressure gauges at the wellhead. The displacement of drilling fluid is calculated based on the mud pump readings. The air injection displacement is measured according to the gas flowmeter, and the cutting displacement is calculated based on the mechanical drilling speed.

where I and j are the time and space nodes, respectively, and Δs and Δt are the space and time steps, respectively. Basic parameters obtained in step 1 are substituted into the discrete formula to calculate the gas injection displacement of current step, qg, as well as the pressure, gas velocity, drilling fluid return velocity, cutting return velocity, and cutting concentration distribution along the drilling fluid return pipeline at a depth of h1 for the gas injection pipeline.

The basic simulation parameters are the actual parameters of a wellbore in the South China Sea, which include a well depth of 3,918 m, water depth of 1,340 m, drilling fluid density of 1,200 kg/m3, mechanical rate of penetration of 40 m/h, injection pipe depth of 400 m, diameter of 50 mm, injection gas flow of 120 m3/h, and inner diameter of drilling fluid return pipeline of 80 mm.

With the same pumping parameters, the drilling fluid displacement varies from 5 L/s to 40 L/s with 5 L/s increments. The multiphase flow model for the closed-cycle riserless drilling is used during the analysis, and the influence of subsea pump displacement on the multiphase flow in the return pipeline is examined, as demonstrated in Figure 3. The simulation results indicate that in the section mudline, the pressure along depth inside the return pipeline increases with increasing drilling fluid displacement values; moreover, in the section below mudline, the pressure along depth inside the return pipeline decreases with increasing drilling fluid displacement. This is because the subsea pump is located at the mudline level. In the section above the mudline, increasing the liquid phase displacement will result in higher subsea pump discharge pressure and larger fluid kinetic energy in the pipeline. Hence, the pressure inside the pipe increases. In the section below mudline, as the fluid in the pipeline is not affected by the subsea pump, the well bottom pressure decreases with an increasing drilling fluid displacement, decreasing the pressure inside the pipeline.

As illustrated in Figure 4, the variation in drilling fluid displacement affects the cutting distribution inside the return pipeline. Higher displacement yields smaller volume fraction of cuttings in the pipeline. Affected by the gas injection in the pipeline at 400 m, the volume fraction of cuttings gradually decreases along the return pipeline and eventually becomes consistent. Gas injection will enhance the turbulence intensity of the fluid in the pipeline, which increases the fluid flow velocity and decreases the sectional volume fraction of cuttings. Therefore, migrating cuttings to the wellhead becomes easier.

Effect of drilling fluid displacement on gas volume fraction inside the return pipeline is calculated and demonstrated in Figure 5. As the gas migrates from the gas injection point at a depth of 400 m, the gas volume fraction decreases with increasing drilling fluid displacement. When the drilling fluid displacement is 5 L/s, 10 L/s, 15 L/s, 20 L/s, 25 L/s, 30 L/s, 35 L/s, and 40 L/s, the gas volume fraction returning to the wellhead is 0.913, 0.846, 0.787, 0.737, 0.692, 0.653, 0.617, and 0.586, respectively. Lowering the subsea pump displacement will result in a larger sectional gas volume fraction in the pipeline, which significantly increases effects of gas injection on cutting migration. As shown in Figure 6, during the upward migration of gas along the pipeline, the flow velocity first increases slowly and then rapidly owing to the gas volume expansion. The gas velocity in gas injection section increases gradually with an increasing drilling fluid displacement. The effects of a fluid displacement lower than 15 L/s are more significant compared with those of other setpoints.

The drilling fluid displacement is closely associated with pump lifting power. As illustrated in Figure 7, the results of calculating the drilling fluid displacement effect on pump lifting power indicate that a higher drilling fluid displacement results in a higher subsea pump working power, which exhibits a nonlinear relationship. During the actual riserless drilling process, considering the power configuration of drilling platform or drilling ship, the subsea pumps should be selected to combine the effects of sites and amount of gas injection. Moreover, to optimize cutting carrying efficiency, a minimum drilling fluid displacement is obtained for selecting the corresponding pump power, which serves as a theoretical basis for selecting the proper subsea pumps.

The most prominent characteristic of novel riserless drilling is the combination of gas injection and subsea pump lift processes. The variations in the gas injection displacement has great impact on the pressure and volume fraction in the pipeline as well as the subsea pump power. By setting the gas injection displacement to 60 m3/h, 80 m3/h, 100 m3/h, 120 m3/h, 140 m3/h, 160 m3/h, 180 m3/h, and 240 m3/h, the effect of gas injection displacement on the multiphase flow in wellbore can be calculated.

As shown in Figure 8, the pressure along depth inside the return pipeline decreases with increasing gas injection displacement values above the mudline level. In the section below the mudline, the gas injection displacement has no effect on pressure in the pipeline is shown. Therefore, in this study, only pressure simulation results in the section above mudline are considered. Affected by gas injection displacement, the discharge pressure of the subsea pump fluctuates greatly. When the gas injection displacement changes from 60 m3/h to 240 m3/h, the pump discharge pressure decreases from 17.288 to 5.527 MPa. A higher gas injection displacement results in smaller pressure losses in the return pipeline and a higher pressure in the pipeline with the same depth.

Gas injection displacement is crucial for ensuring the efficient migration of cuttings and enhance the pumping capacity. Figure 9 demonstrates the effect of varying gas injection displacement using an injection site at 400 m on the gas volume fraction in the return pipeline. A larger gas injection displacement results in a higher gas proportion and fluid kinetic energy throughout the section inside the pipeline; therefore, cuttings can be carried to the wellhead more easily. From the calculation procedure depicted in Figure 10, the gas flow velocity increases with increasing gas injection displacement; its cutting carrying capacity is enhanced significantly as well. When the gas injection displacement elevates from 60 m3/h to 240 m3/h, the gas flow velocity at the wellhead increases from 0.8182 m/s to 3.273 m/s.

The effect of gas injection displacement on pump power is analyzed, which can greatly decrease the load-bearing capacity of pump. By increasing gas injection displacement, the subsea lifting pump power decreases (see Figure 11). Especially in the case of low gas injection displacement, its effect on pump power is more significant. As gas injection displacement elevates from 60 m3/h to 120 m3/h, the pump power decreases by 8.28 kW. In the case of high gas injection displacement, as gas injection displacement increases from 180 m3/h to 240 m3/h, the pump power decreases by 6.01 kW. Therefore, the subsea pump and gas lifting equipment cannot be operated at a high operation efficiency simply by constantly increasing the gas injection displacement. Consequently, in the design stage, the lifting capacity of subsea pump and optimal gas injection displacement should be thoroughly considered.

Gas injection displacement and sites are the key parameters of gas lifting. Properly selecting the gas injection sites significantly affects the subsea pump power requirements. The interaction between the depth of gas injection sites and pump lifting power is calculated as shown in Figure 12. Keeping the gas injection displacement constant, as the depth of gas injection sites increases, the subsea pump power requirement is reduced with a decreasing slope. As the gas injection site depth changes from 100 to 400 m, the pump power decreases from 57.255 to 49.14 kW, an 8.115 kW reduction. As the gas injection site depth changes from 400 to 700 m, the pump power is reduced by 2.903 kW. A deeper gas injection site results in higher requirements for the air compressor on the platform. Based on the conditions of this example, the recommended depth of gas injection site is 400 m.

During deepwater drilling, as seawater depth increases, the requirements regarding drilling equipment and engineering risks will increase as well. The subsea pumping power variations with respect to different seawater depths are calculated as illustrated in Figure 13. The calculation results exhibit that as seawater depth increases, the subsea pump lifting power increases almost linearly. The subsea pump power requirements increase with an increasing depth, during which the effect of gas lifting increases as well. Based on the conditions of this example, subsea pump power increases by 4.97 kW for every additional 100 m in seawater depth.

The novel deepwater closed-cycle riserless drilling method with a subsea pump + gas combined lift aims to address the marine environment pollution and poor wall protection issues caused by open-cycle drilling operation, while avoiding the high costs and risks associated with drilling operations that use risers. In a conventional closed-cycle riserless drilling system, the return of mud is only powered by the subsea lifting pump. Therefore, the flow rate and cutting carrying effect of mud return can be solely controlled by adjusting the lifting pump. For the novel deepwater closed-cycle riserless drilling method with a subsea pump + gas combined lift, the interaction between process parameters of gas lift and flow pattern of mud return, as well as the coupling between each process parameter during pump + gas combined lifting, should be considered to achieve efficient cutting carrying.

In a fixed deepwater drilling block, given the drilling depth, seawater depth, and other drilling parameters, the minimum return velocity of cutting carrying and its corresponding subsea pump rated power with gas lifting can be calculated. By designing orthogonal experiments, the subsea pump power can be simulated and calculated, which can fulfill the cutting carrying requirements with respect to different gas injection depths of gas injection pipeline, gas injection displacements, and drilling fluid displacements. The minimum subsea pump power is selected to optimize and maximize the cutting carrying efficiency by gas injection. In the block with large seawater depth, it might be preferred to first increase gas injection displacement and then increase the depth of gas injection sites. Consequently, the subsea pump load can be decreased as much as possible; in other words, a high-efficiency deepwater drilling process with a low-power subsea pump can be achieved.

The multiphase flow model of the deepwater closed-cycle riserless drilling with a subsea pump + gas combined lift has been proposed to analyze the effects of drilling fluid displacement, gas injection displacement, gas injection site, and seawater depth on the multiphase flow in the novel closed-cycle riserless drilling wellbore. Subsequently, the following conclusions are obtained:

(1) With increasing drilling fluid displacement, the volume fraction of cuttings in the pipeline decreases; whereas, the gas velocity in gas injection pipeline increases gradually. When the drilling fluid displacement is lower than 15 L/s, the effects are more prominent.

(2) With increasing gas injection displacement, it is easier to carry the cuttings and return them to the wellhead, which reduces the subsea lifting pump power requirement.

JW Overall structure design and numerical simulation. JS: Multiphase flow model of closed-cycle riserless drilling biulding. WX: Advantages of the novel subsea closed-cycle riserless drilling method using a pump + gas combined lift in deep-sea drilling analysis. HC: Mesh generation and solution of multiphase flow model. CW: Effect of gas injection site on the subsea pump lifting power analysis and language check. YY: Effect of seawater depth on the subsea pump lifting power analysis. RQ: Optimization of hydraulic parameters analysis.

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Researchers have shown that mud pulse telemetry technologies have gained exploration and drilling application advantages by providing cost-effective real-time data transmission in closed-loop drilling operations. Given the inherited mud pulse operation difficulties, there have been numerous communication channel efforts to improve data rate speed and transmission distance in LWD operations. As discussed in “MPT systems signal impairments”, mud pulse signal pulse transmissions are subjected to mud pump noise signals, signal attenuation and dispersion, downhole random (electrical) noises, signal echoes and reflections, drillstring rock formation and gas effects, that demand complex surface signal detection and extraction processes. A number of enhanced signal processing techniques and methods to signal coding and decoding, data compression, noise cancellation and channel equalization have led to improved MPT performance in tests and field applications. This section discusses signal-processing techniques to minimize or eliminate signal impairments on mud pulse telemetry system.

At early stages of mud pulse telemetry applications, matched filter demonstrated the ability to detect mud pulse signals in the presence of simulated or real noise. Matched filter method eliminated the mud noise effects by calculating the self-correlation coefficients of received signal mixed with noise (Marsh et al. 1988). Sharp cutoff low-pass filter was proposed to remove mud pump high frequencies and improve surface signal detection. However, matched filter method was appropriate only for limited single frequency signal modulated by frequency-shift keying (FSK) with low transmission efficiency and could not work for frequency band signals modulated by phase shift keying (PSK) (Shen et al. 2013a).

In processing noise-contaminated mud pulse signals, longer vanishing moments are used, but takes longer time for wavelet transform. The main wavelet transform method challenges include effective selection of wavelet base, scale parameters and vanishing moment; the key determinants of signal correlation coefficients used to evaluate similarities between original and processed signals. Chen et al. (2010) researched on wavelet transform and de-noising technique to obtain mud pulse signals waveform shaping and signal extraction based on the pulse-code information processing to restore pulse signal and improve SNR. Simulated discrete wavelet transform showed effective de-noise technique, downhole signal was recovered and decoded with low error rate. Namuq et al. (2013) studied mud pulse signal detection and characterization technique of non-stationary continuous pressure pulses generated by the mud siren based on the continuous Morlet wavelet transformation. In this method, generated non-stationary sinusoidal pressure pulses with varying amplitudes and frequencies used ASK and FSK modulation schemes. Simulated wavelet technique showed appropriate results for dynamic signal characteristics analysis.

As discussed in “MPT mud pump noises”, the often overlap of the mud pulses frequency spectra with the mud pump noise frequency components adds complexity to mud pulse signal detection and extraction. Real-time monitoring requirement and the non-stationary frequency characteristics made the utilization of traditional noise filtering techniques very difficult (Brandon et al. 1999). The MPT operations practical problem contains spurious frequency peaks or outliers that the standard filter design cannot effectively eliminate without the possibility of destroying some data. Therefore, to separate noise components from signal components, new filtering algorithms are compulsory.

Early development Brandon et al. (1999) proposed adaptive compensation method that use non-linear digital gain and signal averaging in the reference channel to eliminate the noise components in the primary channel. In this method, synthesized mud pulse signal and mud pump noise were generated and tested to examine the real-time digital adaptive compensation applicability. However, the method was not successfully applied due to complex noise signals where the power and the phases of the pump noises are not the same.

Jianhui et al. (2007) researched the use of two-step filtering algorithms to eliminate mud pulse signal direct current (DC) noise components and attenuate the high frequency noises. In the study, the low-pass finite impulse response (FIR) filter design was used as the DC estimator to get a zero mean signal from the received pressure waveforms while the band-pass filter was used to eliminate out-of-band mud pump frequency components. This method used center-of-gravity technique to obtain mud pulse positions of downhole signal modulated by pulse positioning modulation (PPM) scheme. Later Zhao et al. (2009) used the average filtering algorithm to decay DC noise components and a windowed limited impulse response (FIR) algorithm deployed to filter high frequency noise. Yuan and Gong (2011) studied the use of directional difference filter and band-pass filter methods to remove noise on the continuous mud pulse differential binary phase shift keying (DBPSK) modulated downhole signal. In this technique, the directional difference filter was used to eliminate mud pump and reflection noise signals in time domain while band-pass filter isolated out-of-band noise frequencies in frequency domain.

Other researchers implemented adaptive FIR digital filter using least mean square (LMS) evaluation criterion to realize the filter performances to eliminate random noise frequencies and reconstruct mud pulse signals. This technique was adopted to reduce mud pump noise and improve surface received telemetry signal detection and reliability. However, the quality of reconstructed signal depends on the signal distortion factor, which relates to the filter step-size factor. Reasonably, chosen filter step-size factor reduces the signal distortion quality. Li and Reckmann (2009) research used the reference signal fundamental frequencies and simulated mud pump harmonic frequencies passed through the LMS filter design to adaptively track pump noises. This method reduced the pump noise signals by subtracting the pump noise approximation from the received telemetry signal. Shen et al. (2013a) studied the impacts of filter step-size on signal-to-noise ratio (SNR) distortions. The study used the LMS control algorithm to adjust the adaptive filter weight coefficients on mud pulse signal modulated by differential phase shift keying (DPSK). In this technique, the same filter step-size factor numerical calculations showed that the distortion factor of reconstructed mud pressure QPSK signal is smaller than that of the mud pressure DPSK signal.

Study on electromagnetic LWD receiver’s ability to extract weak signals from large amounts of well site noise using the adaptive LMS iterative algorithm was done by (Liu 2016). Though the method is complex and not straightforward to implement, successive LMS adaptive iterations produced the LMS filter output that converges to an acceptable harmonic pump noise approximation. Researchers’ experimental and simulated results show that the modified LMS algorithm has faster convergence speed, smaller steady state and lower excess mean square error. Studies have shown that adaptive FIR LMS noise cancellation algorithm is a feasible effective technique to recover useful surface-decoded signal with reasonable information quantity and low error rate.

Different techniques which utilize two pressure sensors have been proposed to reduce or eliminate mud pump noises and recover downhole telemetry signals. During mud pressure signal generation, activated pulsar provides an uplink signal at the downhole location and the at least two sensor measurements are used to estimate the mud channel transfer function (Reckmann 2008). The telemetry signal and the first signal (pressure signal or flow rate signal) are used to activate the pulsar and provide an uplink signal at the downhole location; second signal received at the surface detectors is processed to estimate the telemetry signal; a third signal responsive to the uplink signal at a location near the downhole location is measured (Brackel 2016; Brooks 2015; Reckmann 2008, 2014). The filtering process uses the time delay between first and third signals to estimate the two signal cross-correlation (Reckmann 2014). In this method, the derived filter estimates the transfer function of the communication channel between the pressure sensor locations proximate to the mud pump noise source signals. The digital pump stroke is us