creative commons mud pump oil and gas free sample

A mud pump is a reciprocating piston/plunger device designed to circulate drilling fluid under high pressure (up to 7500 PSI) down the drill string and back up the annulus.

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All oil and gas wells undergo multiple cementing operations during their lifetime. During construction, a steel casing is inserted into newly drilled sections of borehole and is cemented into place (primary cementing). As the well descends deeper into the earth, the operation is repeated as successive casings are cemented into place. Objectives of this operation include (i) mechanical support for the well, (ii) hydraulically sealing the annular region outside the casing, (iii) preventing fluid migration along the well, and (iv) preventing corrosive formation brines from reaching the casing. Additionally, at various times during well construction, remedial operations must be executed and at the end-of-life stage, wells are permanently abandoned. Here, cement plugs are commonly used. Both operations are outlined and discussed in depth by Nelson and Guillot (2006).

The fluid flows that occur in cementing operations are characterized by the pumping of multiple fluid stages along a flow path. The volumes are such that normally each fluid stage interacts only with those before/after. The in situ fluid is typically a drilling mud, which must be removed and replaced with the cement slurry, ensuring an adequate bond of the cement to both casing and formation. Drilling fluids have been described above. Due to cement-mud incompatibility, a number of pre-flushes are pumped ahead of the cement slurry. These are loosely classified into washes and spacers. Cement slurries are fine colloidal suspensions that react (relatively slowly) during hydration. The rheology of cement slurries is discussed below in “Rheology of cement slurries” section. All these fluids are generally of different densities and are typically characterized rheologically as shear-thinning yield stress fluids, although this is of course a pragmatic simplification.

The function of washes is to thin and disperse the mud. The wash is usually water-based (or simply water) and becomes turbulent due to its low viscosity. Washes contain similar dispersants as in cement slurries and may also contain surfactants if oil-based fluids are to be removed. Spacers are viscous fluids custom designed to prevent mud-cement contact/contamination and aid mud removal. The term spacer includes relatively low viscosity suspensions that may follow the wash in turbulent flow, fluids such as scavenger slurries (low density cement) but in more recent years has increasingly meant fluids that are sufficiently viscous to generally be pumped in inertial laminar regimes. These fluids are varied and proprietary, but commonly include a combination of viscosifiers (e.g., polyacrylamides, cellulose derivatives, xanthan/bio-polymers, clays such as bentonite); dispersants (e.g., polynapthalene sulfonate); fluid loss agents; weighting agents (e.g., barite, fly-ash, hematite), surfactants, and other optional chemicals, e.g., NaCl/KCl, to inhibit dissolution/damage of certain formations. In general, the idea of a laminar spacer is to have density and effective viscosity intermediate between the cement slurry and drilling mud, eliminating chemical incompatibilities. Examples and more information may be found in Nelson and Guillot (2006).

The main fluid mechanical focus of primary cementing is on removing the drilling mud from the annulus, replacing it with cement slurry that can bond to both the outside of the casing and inside of the borehole, setting hard. Detrimental effects arise if either the mud is not removed or if there is excessive mixing of the cement slurry with other fluids. The former can result in porous hydraulic pathways along the well, caused by dehydration of the mud as the cement sets. The latter can result in contamination that can prevent the hydration reactions from completing and the cement from hardening. The risk in either case is that reservoir gases can migrate along the cemented borehole, leaking to surface.

Thus, cementing flows of interest tend to be fluid-fluid displacement flows. The regular flow geometries are the pipe or eccentric annulus, both of which are inclined relative to gravity. Pump rates used can place the flows anywhere in the laminar to fully turbulent range. Generally speaking, considering a two-fluid displacement: six dimensional and two dimensionless parameters describe the fluids; two to four parameters describe the geometry, plus an inclination angle, plus gravitational acceleration and a flow rate. Following a dimensional analysis, 10–12 dimensionless groups describe the full range of flows, meaning that exhaustive study of these flows is practically impossible. This physical and parametric complexity is part of the challenge of understanding cementing. The other aspect that makes cementing flows difficult is that unlike drilling, these are single volume flows, by which we mean that the in situ fluids are to be replaced by the cement slurry and other fluids pumped. There is no continual circulation to allow monitoring of the flows, there is generally little downhole instrumentation/monitoring during the operation, and post-placement evaluation of job effectiveness is limited.

The importance of the yield stress to primary has been acknowledged for at least 60 years, since the possibility of a mud channel forming on the narrow side of the annulus was first identified (McLean et al. 1966). This occurs if the axial pressure gradient is insufficient to move the mud, which leads to a simple operational rule. In the 1970s–1980s, cementing companies developed their own systems of design rules, purported to mobilize drilling mud and to ensure a steady displacement front advancing along the well, e.g., Jamot (1974), Lockyear and Hibbert (1989), Lockyear et al. (1990), Guillot et al. (1990), and Couturier et al. (1990). The physical reasoning behind such systems was based largely on developing simplified hydraulic analogies. These methods were generally targeted at laminar displacements in near-vertical wells (with turbulent displacements being regarded as anyway effective).

Since the 1990s, these methods have been re-examined and improved. Firstly, the advent of highly deviated and horizontal wellbores in the 1990s led to the identification of new problems for primary cementing; see Keller et al. (1987), Crook et al. (1987), and Sabins (1990). Among the fluid mechanics issues, large density differences tend to cause slumping towards the lower side of the annulus in highly deviated sections and settling effects in cement slurries are amplified. Secondly, computational fluid mechanics models have become a valuable predictive tool, and thirdly, there have been a number of concerted laboratory scale experimental studies of displacement flows. Below, we review those studies of flows in the different cementing geometries.

Most cementing operations involve a pipe flow from surface down the well. Cement slurries are usually denser than drilling fluids, so that this displacement process is frequently mechanically unstable. Efforts are made to separate fluids physically with rubberized plugs, but operational constraints mean that these are frequently missing or only separate one or two interfaces. In plug cementing and remedial operations, smaller diameter tubing is common and separating plugs are not common. Consequently, it is of interest to study density unstable displacement flows of miscible fluids in long inclined pipes.

Miscible Newtonian displacement flows in pipes have been studied for many years. High Péclet number flows at low-moderate Reynolds numbers have been studied computationally (Chen and Meiburg 1996) and experimentally (Petitjeans and Maxworthy 1996), for limited ranges of pipe inclination and density differences. Effects of flow rate and viscosity ratio were studied in vertical displacement flows by Scoffoni et al. (2001), identifying stable finger, axisymmetric and corkscrew modes. Other experimental studies of vertical displacement flows include (Kuang et al. 2004; Balasubramaniam et al. 2005) investigating instabilities due to viscosity and density effects. All these flows are more structured than those found in cementing, which although laminar are significantly inertial, buoyant and include non-Newtonian effects.

A systematic extension of these studies towards cementing displacements is ongoing, focusing initially on Newtonian fluids, buoyancy, viscosity differences, effects of pipe inclination, and flow rate. The effects of increasing the mean flow velocity (\(\hat {V}_{0}\)) on near-horizontal displacement flows are studied in Taghavi et al. (2010), identifying three main regimes as \(\hat {V}_{0}\) was increased from zero. At low \(\hat {V}_{0}\), the flow resembles the exchange flows of Seon et al. (2005). As \(\hat {V}_{0}\) is increased, the front velocity \(\hat {V}_{f}\) was found to vary linearly with \(\hat {V}_{0}\). The first two of these regimes may be either viscous or inertial-dominated. When the mean speed is further increased, we enter the turbulent regime where \(\hat {V}_{f}=\hat {V}_{0}\). The behavior of the trailing displacement front was studied in Taghavi et al. (2011). A synthesis of the results on iso-viscous nearly horizontal displacement flows is presented in Taghavi et al. (2012c), based on a mix of experimental, numerical, and analytical results. These studies have been extended to the full range of pipe inclinations (Alba et al. 2013a), partly also to density stable displacements (Alba et al. 2012). Ongoing work is focused on studying viscosity ratio effects and shear-thinning behavior, where a variety of interesting instabilities are found.

Regarding yield stress effects, the field is less well explored. When the displaced fluid has a yield stress, it is possible for the flow to leave behind residual fluid layers stuck to the wall, which remain permanently. These are illustrated in the elegant study of Gabard-Cuoq (2001) and Gabard-Cuoq and Hulin (2003) in which vertical displacement of Carbopol solutions by glycerin results in beautifully uniform stationary residual layers. More recent work has focused on the case of a dominant yield stress (e.g., a drilling mud that is hard to displace) and displacing with density unstable Newtonian fluids; see Taghavi et al. (2012b), Alba et al. (2013), and Alba and Frigaard (2016). These flows result in two primary flow types: central displacement and slump displacements, distinguished parametrically by an Archimedes number. The slump displacements show a wonderful range of complex flow patterns, including those that rupture the displaced fluid and spiral patterns; see, e.g., Fig. 1. The stratified viscous regimes of Taghavi et al. (2010) and Taghavi et al. (2012c) have been modelled for two Herschel-Bulkley fluids; see Moyers-Gonzalez et al. (2013), but experimental reality in cementing regimes rarely conforms to the strict model assumptions. Ongoing research has studied the central regime extensively (in the absence of any density difference; Moises 2016) and studied vertical pipes with a range of positive and negative density differences.

The second and most critical displacement geometry is the annular space formed by the outside of the steel casing and the inside of the borehole. Typically, the mean annular gap is in the range 1–3 cm, but even when wells are vertical, the annulus is eccentric. Modern wells typically start with a vertical section (surface casing) and end up aligning directionally with the reservoir (production casing). Cemented sections are typically many hundreds of meters long, and the diameters of the steel casings decrease with depth. The annulus is initially filled with drilling mud which should be pre-circulated for conditioning prior to the displacement. Displacing fluids enter the annulus at the bottom and move upwards to surface: the detrimental unstable density difference inside the casing is now stabilizing. Whatever mixing has occurred inside the casing between fluids is now transferred to the annular displacement.

The majority of fluid mechanic studies have focused on laminar displacement flows. A popular approach has been to average the velocity field across the narrow annular gap, thus reducing the flow to a 2D problem for the gap-averaged velocity field. The earliest developments were by Martin et al. (1978). A further-simplified pseudo-2D approach was developed and validated against a series of experiments in Tehrani et al. (1992, 1993), and this style of model was also derived and solved computationally in Bittleston et al. (2002). Fully 2D computations, a rigorous analysis of the model and comparisons with some of the rule-based systems can be found in the series of papers (Pelipenko and Frigaard 2004a, b, c), targeted at near-vertical displacements. For example, in Pelipenko and Frigaard (2004c), it is shown that rule-based systems such as the earlier (Couturier et al. 1990), although physically sensible, can be extremely conservative in the requirements needed for an effective displacement. Near-vertical experiments and model comparisons were made in Malekmohammadi et al. (2010). Strongly inclined and horizontal wells have been studied in Carrasco-Teja et al. (2008a, b) and more recently, the effects of casing rotation have been studied in Carrasco-Teja and Frigaard (2009, 2010) and Tardy and Bittleston (2015). Qualitatively, this level of modelling is adaptable to rather complex wellbore geometries and has been shown to identify bulk features of the flow, such as mud channels remaining stuck on the narrow side of the wellbore, see Fig. 2, for an example. Such models are appropriate for process design and predict well the dominant effects of wellbore eccentricity, rheology, density differences, and inclination. Variants of this approach are increasingly widely used in industry, e.g., Tardy and Bittleston (2015), Guillot et al. (2007), Chen et al. (2014), and Bogaerts et al. (2015). It is interesting to reflect that the above approach is mathematically analogous to the LPG reservoir flows outlined in “Reservoir flows of visco-plastic heavy oils,” with varying annular gap width corresponding varying permeability.

Displacement using approach of Bittleston et al. (2002) and Pelipenko and Frigaard (2004b). Images show half (wide-narrow side) of an unwrapped vertical annulus (310 ft long, 7 in. ID, 8.9 in. OD, 30% eccentric): 1.68 SG mud (red) with 50 Pa yield stress, displaced by 2.0 SG spacer fluid (blue) with 0.41 Pa yield stress (white = streamlines). Static mud remains

Aside from Tehrani et al. (1992, 1993) and Malekmohammadi et al. (2010), other experimental studies include that of Jakobsen et al. (1991) that investigated a subset of density and rheology differences, eccentricity, inclination, and Reynolds number. A number of authors have studied the annular flows in 3D computationally. For example, Szabo and Hassager (1995, 1997) studied Newtonian displacements in eccentric annular geometries. Comparisons between the 3D computational fluid dynamics (CFD) results of Vefring et al. (1997) and earlier experiments of Jakobsen et al. (1991) are generally favorable. In a modern era of massively parallel computation, one might ask why 3D CFD has not had more impact? The first point here is that advantages over the 2D models come from resolving the scale of the annular gap (cm scale). 3D meshes at that resolution become unmanageable over circumferential distances of ∼0.5 m and wellbore lengths of many hundreds of meters (e.g., \(\gtrsim 10^{9}\) mesh nodes). Secondly, many of the critical features of mud removal displacements concern the yield stress and the residual fluid left behind in the annulus. Reliable implementation of yield stress models into CFD codes, in a way that resolves the unyielded regions properly, results in considerable additional computational iteration compared to a Newtonian fluid flow. Thirdly, there is a question of resolution, data processing, and analysis: the coarse-graining of an averaged approach leads to fairly simple interpretations of displacement results, in much of the annulus nothing much is happening, etc.. Most critical however is certainly the large dimensionless parameter space discussed earlier (10–12 parameters). This rules out systematic study on the scale of the wellbore. Experiments also have issues of scale. In lab scale displacements, the annular lengths used are limited (typically <10 m), which makes interpretation of these studies harder in comparison to 2D models on the wellbore scale.

A different way of resolving the through-gap distribution of fluids is to consider longitudinal sections of the narrow annulus, i.e., as a plane channel displacement. Firstly, lubrication/thin-film approaches have been used, giving a simplified pseudo-2D prediction. This approach dates back to Beirute and Flumerfelt (1977), but with errors in the derivation. Symmetric displacements were considered by Allouche et al. (2000) and inclined channels by Taghavi et al. (2009). The latter work has been extended to include weak inertial effects (Alba et al. 2013b) and more recently to converging-diverging 2D sections by Mollaabbasi and Taghavi (2016). These models allow one to predict the maximal layer of drilling mud that may remain stationary on the wall of the channel (=annulus) and to predict qualitative behaviors of the displacement fronts. Fully 2D simulations and analysis can be found in Taghavi et al. (2012a, c), Allouche et al. (2000), Wielage-Burchard and Frigaard (2011), and Alba et al. (2014). These simulations cover a limited subspace of parameters, which is being currently extended. Figure 3 shows an example of a displacement of a Bingham (drilling) fluid by a Newtonian (spacer) fluid at along a uniform channel of width \(\hat {D}\) at mean imposed velocity \(\hat {V}_{0}\). Two different viscosity ratios are considered: thicker static layers are evident for the more viscous displaced fluid. The focus of these studies is to predict the so-called micro-annuli, i.e., annular wall layers of undisplaced mud extending along the wellbore. As the cement eventually hydrates, these layers dry into porous longitudinal conduits, compromising the annular seal integrity.

r = 0.1; and Bingham number \(B= \hat {\tau }_{Y} \hat {D}/(\hat {\mu } \hat {V}_{0}) = 5\). Left: viscosity ratio (Bingham plastic viscosity/Newtonian viscosity) m = 0.1; right: m = 10. Images at time intervals of \(4\hat {D}/\hat {V}_{0}\)

Many boreholes are drilled into unconsolidated formations. The combination of drill string vibration, jetting through the drill bit and geological weakness, often results in washout sections, i.e., where the annular geometry has a local expansion into the rock formation. These features are largely unpredictable geometrically although they are increasingly measured using caliper logs prior to cementing. It is of interest that some of the earliest experimental studies considered the effects of sudden expansions on the annular geometry, e.g., Clark and Carter (1973) and Zuiderwijk (1974), but this approach was then abandoned experimentally until quite recently, e.g., Kimura et al. (1999). However, although studied experimentally, these works are largely in the form of yard tests: using limited ranges of realistic fluids but not allowing one to draw more general fluid mechanic understanding.

The main issue with irregular washout shapes is that fluids with yield stress (e.g., drilling muds) are known to have regions of zero strain (plugs) and irregular geometries can promote regions of low shear stress close to wall, which result in static zones. In primary cementing, it is common to pre-circulate drilling mud prior to pumping cement, to condition the mud. Thus, it becomes operationally important to estimate the flowing volume of the annulus, particularly washouts. Although single phase, the requirement now is to determine the yield surface bounding immobile mud. Static wall regions also occur in regular uniform ducts, e.g., with cross-sections having corners, (Mosolov and Miasnikov 1965, 1966). Mitsoulis and co-workers (e.g., Mitsoulis and Huilgol 2004) studied both planar and axisymmetric expansion flows, showing significant regions of static fluid in the corner after the expansion. Flow of yield stress fluids through an expansion-contraction has been studied both experimentally and computationally by de Souza Mendes et al. (2007), Naccache and Barbosa (2007), and Nassar et al. (2011). In de Souza Mendes et al. (2007), Carbopol solutions were pumped through a sudden expansion/contraction, i.e., narrow pipe–wide pipe–narrow pipe, with yield surfaces visualized by particle seeding. Stagnant regions first appear in the corners of the expansion, grow with increasing yield stress, and become asymmetric with increasing Reynolds number. In Roustaei and Frigaard (2013), large amplitude wavy-walled channel flows were studied numerically, predicting the onset of stationary fluid regions, which occur initially at the walls in the widest part of the channel. A more comprehensive study of geometrical variation was carried out in Roustaei et al. (2015). Yield stress fluid becomes trapped in sharp corners and small-scale features of the washout walls and fills the deepest parts of the washout as the depth (\(\hat {H}\)) is increased. For sufficiently large yield stress (\(\hat {\tau }_{Y}\)) and sufficiently deep washouts (\(\hat {H}\)), the actual washout geometry has little effect on the amount of fluid that is mobilized: for a deep washout, the flowing fluid “self-selects” its geometry. Figure 4 shows an example of this flowing area invariance. Having established stationary regions within the depths of the washout, further increasing \(\hat {H}\) does not significantly affect the position of the yield surface. In Roustaei and Frigaard (2015), inertial effects were considered, for similar flows as in Roustaei et al. (2015). Surprisingly, moderate Reynolds numbers (but laminar) can in fact result in a reduction in flowing area, contrary to industrial intuition that pumping faster is better.

Example Stokes flows computed through washout geometries of increasing depth, imposed on a uniform channel of width \(\hat {D}\). Speed colour map (normalized with mean velocity \(\hat {V}_{0}\)), streamlines, and gray plug regions: Bingham number \(B = \hat {\tau }_{Y} \hat {D}/(\hat {\mu } \hat {V}_{0})=5\). Flow is from left to right and the washouts are assumed symmetric (left-right) so that only half the domain is computed

Plug cementing occurs principally when abandoning wells, although sometimes also earlier in construction. In this process, plugs of ∼100 m of cement are placed along the wellbore to seal it permanently. Before around 2000, it was relatively uncommon to provide any mechanical support to the cement, with the result that the heavy cement slurry frequently exchanged places with the less dense fluids below, in a destabilizing exchange flow. These flows (heavy fluid over light fluid in a pipe with zero net flow) have received considerable attention in the scientific literature (exchange flows), for Newtonian fluids. In plug cementing, the fluids have a yield stress, which can prevent this mechanically unstable motion, and some features of these flows have been studied. In more recent years, it has become common to use a mechanical support under each cement plug, removing the interesting buoyancy-driven exchange flow. However, the actual plug placement still contains many of the features of the primary cementing displacement: downward flow of fluid stages through a pipe and removal (displacement) of the wellbore fluids around the outside of the tubing.

However, the pipe/tubing used to place the plugs is generally smaller than the casing in primary cementing. Thus, the annular placement geometry is no longer narrow. Indeed, some jurisdictions require the existing casing to be milled out into the surrounding rock formation. The fluids within the well may then be either old production fluids, possibly weighted brines, or drilling muds from the milling operation. Undoubtedly, this all makes the annular displacement problem harder. As a further complication, while the cement is pumped, the tubing is often slowly withdrawn from the hole, which leads to buoyancy-driven motion re-balancing of the static pressures between tubing and annulus.

Cement is composed of calcium silicate and calcium aluminate phases. At the moment cement particles and water come into contact during mixing to form the slurry, chemical reactions begin. These reactions are collectively called hydration. The hydration products of silicate phases are CHS (calcium hydrosilicate) and Ca(OH) 2 (calcium hydroxide). The calcium aluminate phases react rapidly with water causing rapid hardening, and hence, the addition of calcium sulfate is needed to avoid early setting (Taylor 1997).

In the early stages, the reactions go through a dormant period (the induction stage) of typically a few hours, after which setting initiates and the slurry progressively hardens. During the dormant period, the slurry is said to be fresh. A fresh slurry can be pumped and flow to the region where it is supposed to harden later on. Therefore, a reliable design of cementing operations requires a thorough understanding of the mechanical behavior of the fresh cement slurries (Banfill 1997). In well cementing, retarders are used to control the length of the induction stage, allowing a safety margin for pumping operations to complete.

The rheology of fresh cement slurries is a strong function of the mixing method (Yang and Jennings 1995), because hydration kinetics will depend on the mixing efficiency. At the moment mixing is started, a suspension of aggregates of cement particles forms. The particles are held together in the aggregate by action of an enveloping membrane of hydrated minerals that forms instantaneously. The strength of this membrane is quite high, approaching that of a typical chemical bond between atoms, whereas links between particles—due to van der Waals attraction force—are one order of magnitude weaker (Banfill 1997). Therefore, hydration efficiency will depend directly to what extent the mixing process is successful in rupturing the membranes and thus breaking the initially formed aggregates.

Other factors also have important effect on the rheology of fresh cement slurries, namely the water/cement ratio, temperature, cement fineness, cement type, and the content of admixtures, polymer latexes, flyash, slag, limestone, microsilica, and so on Banfill (1997).

Rheological measurements with cement slurries are rather difficult, due to many potential sources of measurement error. Therefore, good laboratory data requires sophisticated rheometers operated by experienced rheologists. In practical applications of the oil and gas industry, however, it is seldom possible to employ advanced laboratory rheometers, and the usual consequence is lack of reproducibility. The main experimental difficulties and suggested cures are now briefly discussed. A thorough discussion about this topic is found elsewhere (Roussel 2012).The sample preparation requires a rigid protocol for the quality of water and cement, mixing method, and sample loading in the rheometer.

The choice of geometry and gap should take into account:The presence of solid particles, which requires gaps at least 10 times the characteristic particle size. This requirement typically precludes the usage of the cone-plate geometry.

Due to the highly thixotropic and sometimes elastic nature of fresh cement slurries, in flow curve and oscillatory experiments, it is of central importance to make sure that all (non-periodic) transient effects have faded out before any data point is registered.

Shrinkage due to drying is likely to occur, introducing important measurement error. It may be avoided by providing a water-saturated atmosphere around the sample, i.e., using the so-called solvent trap and cap.

Sedimentation is one of the great challenges found in the rheometry of cement slurries. The large density difference between the dispersed phase and water often leads to sedimentation, especially in the high end of the range of water/cement ratio. To reduce and control sedimentation, chemical additives are often included in the slurry composition (Al-Yami 2015). The additives are selected to perform satisfactorily for application purposes. However, even for a slurry that does not exhibit significant settling problems when pumped downhole, sedimentation may still undermine the quality of rheological data. For example, for the parallel-plate geometry, a depleted layer is formed adjacent to the upper plate, leading to grossly underestimated viscosities.

For the Couette geometry, sedimentation causes a stratified viscosity distribution, and the measured value again does not correspond to the viscosity of the homogeneous sample. When it is not possible to obtain reliable data before appreciable settling occurs, one remedy to circumvent sedimentation includes the usage of a modified bob in the Couette geometry that possesses helical grooves which help maintaining homogeneity. The grooves cause a significant departure from the purely tangential flow assumed in the rheometer theory, and therefore, an error is introduced. It is important to estimate the effect of the grooves and re-calibrate, e.g., by running preliminary tests with standard oils.

An interesting alternative to reduce sedimentation is to increase the viscosity of the continuous phase with the aid of some additive and then present the data in the form of relative viscosity, namely the viscosity of the slurry divided by the viscosity of the thickened continuous phase. Therefore, to obtain the viscosity of the original slurry (without the additive), it suffices to multiply the measured relative viscosity by the viscosity of water. Of course, this method is not free of artifacts and should be used cautiously. The viscosity thus obtained will to some extent deviate from the correct one due to possible qualitative changes of the interactions between the continuous and dispersed phase.

Oil drill operations rely on the use of derricks for their production. An oil derrick is used to dig a hole for an oil well, then to push the drill pipe deep into the earth. A mud mixture is sprayed from the drill bit to push material from the cuttings up out of the hole and cool the drill equipment, as well as to keep the bore hole stable. Then a well pipe replaces the drill pipe, so oil can be pumped out, using valves to allow the oil to move up the bore hole without sliding back down. Many workers at oil and gas drilling sites share duties to keep wells operating efficiently and safely. Derrick operators and rotary drill operators keep the mud, made of water, clay, air, and chemicals, flowing, so drills run smoothly. These workers listen to drills to ensure the vibrations are normal and may collect samples of material from the hole to monitor output. Derrick and drill operators place derricks in the correct location and keep them running around the clock, monitoring gauges, repairing equipment, and checking for problems. Drill operators also train drill crews on procedures and safety measures. Wellhead pumpers operate pumps that force oil and gas out of wells and into storage tanks and pipelines. They also monitor other production equipment and ensure that materials are being pumped at the correct pressure, density and concentration. Service unit operators work in oil and gas drilling, as well as mining operations, to troubleshoot drilling issues and resolve them. They use equipment to increase oil flow from producing wells, or to remove stuck pipes, tools, or other obstructions from drilling wells and mining exploration operations. These workers are employed by the oil and gas industry at construction sites and drilling rigs. They may work on offshore oil platforms drilling the ocean floor, or in remote locations in the far north or Middle East, which may require living onsite for long periods. Work may be seasonal, and shifts are often around the clock. Extreme weather conditions and dealing with heights is also part of the job. Machinery is noisy, and safety rules are critical. Wellhead pumpers typically need a high school diploma, while derrick operators, rotary drill operators, and service unit operators typically have no specific education requirements.

I’ve run into several instances of insufficient suction stabilization on rigs where a “standpipe” is installed off the suction manifold. The thought behind this design was to create a gas-over-fluid column for the reciprocating pump and eliminate cavitation.

When the standpipe is installed on the suction manifold’s deadhead side, there’s little opportunity to get fluid into all the cylinders to prevent cavitation. Also, the reciprocating pump and charge pump are not isolated.

The gas over fluid internal systems has limitations too. The standpipe loses compression due to gas being consumed by the drilling fluid. In the absence of gas, the standpipe becomes virtually defunct because gravity (14.7 psi) is the only force driving the cylinders’ fluid. Also, gas is rarely replenished or charged in the standpipe.

Installing a suction stabilizer from the suction manifold port supports the manifold’s capacity to pull adequate fluid and eliminates the chance of manifold fluid deficiency, which ultimately prevents cavitation.

Another benefit of installing a suction stabilizer is eliminating the negative energies in fluids caused by the water hammer effect from valves quickly closing and opening.

The suction stabilizer’s compressible feature is designed to absorb the negative energies and promote smooth fluid flow. As a result, pump isolation is achieved between the charge pump and the reciprocating pump.

The isolation eliminates pump chatter, and because the reciprocating pump’s negative energies never reach the charge pump, the pump’s expendable life is extended.

Investing in suction stabilizers will ensure your pumps operate consistently and efficiently. They can also prevent most challenges related to pressure surges or pulsations in the most difficult piping environments.

Sigma Drilling Technologies’ Charge Free Suction Stabilizer is recommended for installation. If rigs have gas-charged cartridges installed in the suction stabilizers on the rig, another suggested upgrade is the Charge Free Conversion Kits.

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Organoclay suspensions are commonly used as drilling fluids in environments where they are submitted to high pressure and temperature for long periods of time. Consequently, both volumetric and thermorheological properties are among their most important quality parameters concerning this application. The overall objective of this work was to study the pressure and temperature dependence of both viscosity and density for oil-based drilling fluids. With this aim, Pressure-Density-Temperature (PρT) data and pressure-viscosity-temperature data were modeled by using different equations. All these equations predict the evolution of the viscosity of drilling fluids with pressure and temperature, for engineering purposes, fairly well.

Organoclay suspensions are commonly used as oil-based drilling fluids due to their capacity to form gels and their suitable viscous properties. These fluids are submitted to high pressure and temperature in the well during drilling operations. The successful completion of an oil well and its cost depend, on a considerable extent, on the properties of these fluids [1, 2]. Hence, one of the most interesting points for the drilling industry is to develop fluid formulations, using new nanoscale additives [3, 4], in order to improve their thermophysical properties. Both, viscosity and density have been the two most extensively studied properties of organoclay dispersions used as drilling fluids. When drilling fluids are pumped down, they experience compression and expansion effects related to the increase or decrease of temperature and pressure along the wellbore. Density variations might be significant and its control is a challenging goal to minimize associated risks, and improve security and efficiency, particularly for oily systems [5-7]. Several authors have investigated the combined influence of pressure and temperature on the density of drilling fluids [8-11] However, few papers have been focused on the characterization of the Pressure-Volume-Temperature (PVT) relationship for this type of dispersions [12, 13].

In addition, the rheological behavior of oil drilling fluids is a critical issue in the success of drilling operations. Data concerning the influence of high pressure and temperature on the viscous properties of these types of suspensions are relatively scarce [14, 15]. However, knowledge of the flow behavior of clay-based drilling fluids, as a function of temperature and pressure, is of a paramount importance in order to solve different important issues, such as excessive torque, gelation, hole cleaning, etc. [16].

Modeling the thermopiezoviscous behavior of fluids is a relevant issue for engineering applications involving processes at high pressure and temperature [17, 18]. In this sense, different equations based on the friction theory [19], the free-volume concept [20, 21], and empirical correlations [22] have been proposed to model the combined effect of temperature and pressure on the rheological properties of materials.

The overall objective of this work was to study the influence of pressure and temperature on viscosity and density of model oil-based drilling fluids. With this aim, Pressure-Density-Temperature (PρT) data were used to model the volumetric properties of the drilling fluids, by using Equation of State (EoS). Finally, using rheological, PVT, and calorimetric data, the pressure-temperature-viscosity behavior of these suspensions was modeled using different equations, such as Fillers-Moonan-Tschoegl’s (FMT), Yasutomi’s, and WLF-Barus’ models.

A mineral based lubricating oil, SR10 (0.916 g cm−3 at 40 °C) supplied by Verkol (Spain), was used as base oil for the formulation of the model oil-based drilling fluids.

Oil drilling fluids were prepared by mixing the organoclay (5% wt.) in SR10 oil base, using a high mixer Ultraturrax (Ika, Germany), at room temperature, at 9000 rpm for 5 min. Prior to its high shear processing, the organoclay was wetted with the oil for 1 h at room temperature.

Two vibrating tube densimeters were used to measure the density, ρ, of the samples studied. At atmospheric pressure, an Anton Paar DMA 5000 (Austria) was employed to measure the density of SR10 oil and organoclay dispersions between 40 °C and 100 °C. Prior to performing density measurements with oil and organoclay dispersions at atmospheric pressure, the DMA 5000 densimeter was calibrated, as function of temperature, using both dry air and degasified bi-distilled water as recommended by the manufacturer. The results obtained were compared with the values reported in Anton Paar’s manual for air and water in the temperature range used. For this densimeter, the manufacturer cited an uncertainty for temperature of ±0.01 °C, and density of ±5 × 10−6 g cm−3, between 0 °C and 100 °C.

An Anton Paar DMA HPM high-pressure vibrating tube (Austria) was used to measure the density in the temperature range comprised between 40 °C and 140 °C, and pressures up to 1200 bar. The temperature of the high-pressure vibrating tube was controlled by an external circulating bath using silicone. The temperature was maintained constant within ±0.01 °C. A manual piston intensifier (HiP, USA) was used to control the pressure of the system. The pressure applied was measured by a pressure transducer model HP-2-S (Wika, Germany) with an uncertainty of less than 0.5% between 0 and 1600 bar.

Taking into account the accuracies of temperature, pressure, period of oscillation, water and dodecane densities, and Equation (1) fitting for the reference fluids (0.07% for water and 0.1% for dodecane), the overall experimental uncertainty in oil and model oil-based drilling fluid densities is estimated to be ±1 × 10−3 g cm−3. This uncertainty is similar to that previously reported in the literature [25].

Viscous flow measurements were performed using a controlled stress rheometer, MARS II from Thermo Scientific (Germany). Rheological data were obtained using different geometries: a conventional coaxial cylinder geometry (41 mm inner diameter, 1 mm gap, 60 mm length) and a serrated plate-and-plate geometry (35 mm diameter, 1 mm gap) for rheological tests at atmospheric pressure; a coaxial cylinder geometry (38 mm diameter, 80 mm length) and a Double Helical Ribbon (DHR) geometry (36 mm diameter, 78 mm length), coupled with a pressure cell (D400/200), for measurements at high pressure. DHR is a non-conventional geometry, calibrated with a Newtonian fluid and several shear-thinning fluids, in the pressure range used in the present study [26]. The cell D400/200 is a pressure vessel of 39 mm inner diameter. Inside the cell, the coaxial cylinder and the DHR geometry were put in contact with a sapphire surface, at the bottom of the vessel, by a steel needle. The inner geometry was equipped, at the top, with a secondary magnetic cylinder (36 mm diameter, 8 mm length), magnetically coupled to a tool outside the cell, which was connected to the motor-transducer of the rheometer. The pressure cell was connected to a hydraulic pressurization system, which consists of two units, a high pressure valve and a hand pump (Enerpac, USA), connected by a high pressure line. The pressure cell was pressurized using, as pressurizing liquid, the same fluid to be tested. A pressure transducer GMH 3110 (Gresingeg Electronic, Germany), able to measure differential pressures ranging from 0 to 400 bar (0.1 bar resolution), was used.

Steady-state viscosity measurements, at different differential pressures (0, 100, 200, 300 and 390 bar) and temperatures (40, 80, 100, 120 and 140 °C), were performed in a shear rate range dependent on sample viscosity. The temperature in the high pressure cell was regulated with circulating silicone bath (DC30 Thermo Scientific, Germany), with an uncertainty of ±0.1 °C.

Differential Scanning Calorimetry (DSC) tests were carried out with a DSC-Q100 calorimeter (TA Instruments, USA), using 5-10 mg samples sealed in hermetic aluminium pans. The sample was purged with dry nitrogen at a flow rate of 50 mL/min, to avoid any condensation of moisture. First, the pans where placed onto the cell at room temperature, then were heated at 80 °C, kept at this temperature for 5 min to reach the thermodynamic equilibrium, and subsequently, the samples were quenched-cooled to −80 °C, at 10 °C/min, kept for 5 min at this temperature to reach the equilibrium, and, finally, heated, at 10 °C/min, up to 180 °C. The glass transition temperature was determined from the inflection point of the step-like decrease in the heat flow.

Figures 1a and 1b show the steady-state viscous flow curves of the samples studied (SR10 oil, and B34- and B128-based oily fluids), at 80 °C and pressures of 1 and 390 bar respectively. In the case of the oily suspensions, the steady-state viscous flow curves were obtained after upward and downward shear stress sweep tests, as has been described by the authors elsewhere [27, 28].

Experimental steady-state viscous flow curves, and Bingham’s model fitting, for SR10 oil, B34- and B128-based drilling fluids (T = 80 °C; a) P = 1 bar; b) P = 390 bar).

As can be observed in Figure 1, the viscous behavior of the SR10 oil is Newtonian in the pressure range of 1-390 bar, at 80 °C. This oil also behaves as a Newtonian liquid for the whole range of temperature tested (40-140 °C). In contrast, oil drilling fluids show a shear-thinning behavior, exhibiting a Bingham-law dependence of viscosity with shear rate in the whole range of pressure and temperature tested (1-390 bar; 40-140 °C), as has been previously reported [29, 30].

The Newtonian viscosity of the SR10 oil sample increases up to 2.13 times from atmospheric pressure to 390 bar, at 80 °C. However, the viscosity-pressure relationship for the drilling fluids is more complex, depending on both bentonite nature and shear rate. For example, the plastic viscosity increases ~2.11 times for B34 sample and ~2.22 times for B128 sample, in the above-mentioned range of pressure. Nevertheless, at a shear rate of 1 s−1, the plastic viscosity increases ~2.68 times for B34 sample and ~1.34 times for B128 sample. This complex piezoviscous behavior has been related to the development of complex molecular structures with different sensitivities to pressure and shear rate [29].

The thermopiezoviscous behavior of these materials can be modeled using equations developed for thermopiezorheologically simple materials, such as the FMT [30] the Yasutomi [31] or the empirical WLF-Barus factorial model [27]. The approach is based on selecting characteristic rheological parameters, such as the Newtonian viscosity, in the case of the SR10 oil, or the plastic viscosity (ηp) of the model drilling fluids, to eliminate the complex shear-rate dependence of the piezoviscous behavior, fitting the model equations to these selected shear-rate independent parameters.

Viscosity-pressure-temperature models can be also classified as either only based on empirical parameters or based on some physical properties. Thus, the FMT model takes into account the pressure dependence of the bulk modulus and the expansivity. The pressure dependence of these properties can be obtained from the evolution of the density with pressure and temperature using the Murnaghan EoS. The Yasutomi model is described as a function of the glass transition temperature, which can be obtained from DSC measurements. The WLF-Barus model describes the thermopiezoviscous behavior using empirical parameters for both temperature and pressure. To apply either FMT’s or Yasutomi’s model based on physical properties, the bulk modulus or the glass transition temperature should be previously determined by additional experiments.

Figures 2-4 show the values of the density for the different samples studied, as a function of pressure (1-1200 bar) and temperature (40 °C up to 140 °C). As expected, a nearly linear decrease in density with temperature is observed for all samples in the range of temperature studied. Temperature and pressure exert an opposite influence on the volumetric behavior. The decrease in density when temperature is raised from 40 °C to 140 °C is compensated by an increase in pressure from 1 to ~1056 bar, for the SR10 oil and even slightly higher for both oil-based drilling fluids (up to ~1105 and ~1060 for B34 and B128, respectively). Thus, the influence of temperature is more relevant as compared to that of pressure. On the basis of this analysis, both model drilling fluids, B34 and B128, are slightly more susceptible to temperature than the base oil, showing the B34-based drilling fluid the lowest susceptibility to pressure, at 140 °C. These drilling fluids show quite similar temperature susceptibility to that of the synthetic oil-based drilling fluids studied at low pressure [6]. On the contrary, these fluids show higher temperature susceptibility than those studied at high pressure [9].

As can be seen in Figures 2-4, the Murnaghan equation describes the density evolution in the range of temperature and pressure studied fairly well. This equation has been extensively used by other authors to fit data of volumetric properties, as a function of temperature and pressure, of rubbery polymers [33] and heavy petroleum fractions [34]. For these samples, the values of the Percent Average Absolute Relative Deviation (%AARD), shown in Table 1, are lower than 0.07, indicating that this model is suitable for oil-based drilling fluids.

In the range of pressure tested, both oil and drilling fluids show a qualitatively similar linear increase in the bulk modulus with pressure. This fact suggests that the volume-pressure behavior for these fluids is determined by that of the base oil, as has been pointed out by other authors [10]. The values of the bulk modulus, calculated from PVT data, at 1 bar and 80 °C, are similar and slightly higher than those obtained for n-paraffinic based drilling fluids [6] and mineral oil-based mud [8, 9] respectively, being the pressure susceptibility slightly higher for the samples studied.

The range of pressure tested in this research is much narrower than that normally covered for lubricant studies [37]. Consequently, the viscosity-pressure evolution is simpler than that obtained for lubricant oils submitted to higher pressure. In these cases, the Yasutomi equation would be overparameterized, leading to several set of parameters from the regression procedure of the viscosity-pressure data. Consequently, in this fitting process, ηg and B2 have been arbitrarily set to 1012 Pa s and 1 respectively, using the Tg0 values from DSC measurement as additional fixed parameters. The results obtained for the remaining parameters are shown in Table 3.

Figure 7 shows the evolution with pressure of the Newtonian viscosity, for SR10 oil, and the plastic viscosity, for B34- and B128-based oil drilling fluids, at the reference temperature (80 °C) as example. It can be seen that, at constant temperature, viscosity increases exponentially with pressure in the range of pressure tested. In addition, all the three models tested describe the isothermal evolution of viscosity with pressure, for engineering purposes, fairly well.

Experimental and estimated viscosities, using FMT, Yasutomi and WLF-Barus models, for SR10 oil and drilling fluids, as a function of pressure, at 80 °C.

In Figure 8, the experimental viscosity data (in the range 1-400 bar and 40-140 °C) of the samples studied and the calculated ones by using different models are compared (Fig. 8a: FMT’s model; Fig. 8b: Yasutomi’s model; and Fig. 8c: WLF-Barus’ model). As can be seen, the largest deviations between experimental and calculated values are observed for B34 and B128 model drilling fluids, at 140 °C. These deviations, previously explained by the authors [27] are a consequence of the influence, on the rheological behavior of these drilling fluids, of the gelation process induced at high temperature. Excluding the results obtained at the above-mentioned temperature (140 °C), the three models fit the experimental results, in the whole range of temperature and pressure tested, fairly well (average error less than 5%). Nevertheless, on the basis of the %AARD and relative deviation, each model behaves differently depending on the sample. Thus, both FMT’s and WLF-Barus’ models show similar deviations and lower %AARD values for the SR10 oil (~2.3%, Tab. 2-4). B34 drilling fluid shows the highest values of %AARD and lowest R

2 correlation coefficient for any model tested, being WLF-Barus’ model the best fit for this sample. On the contrary, Yasutomi’s model shows the lowest values of the %AARD for the B128 drilling fluid. The use of an empirical exponential function of temperature and pressure to model viscosity data of water-based drilling fluids, oil-based drilling fluids [39] and invert oil mud [40, 41] is very common for engineering purposes, being the average error higher than those found in this research (around 5% [42] or even higher [43]).

From the experimental results obtained, it can be concluded that model oil-based drilling fluid densities are more susceptible to changes in temperature than to pressure. The Murnaghan equation describes the PVT behavior, in the range of temperature and pressure studied, fairly well.

Different models can predict the evolution of the viscosity of drilling fluids with pressure and temperature. In this sense, free-volume models, based on physical parameters, do fit the viscosity-pressure-temperature data fairly well, showing similar or even lower error than some well-known empirical exponential equations.

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Experimental steady-state viscous flow curves, and Bingham’s model fitting, for SR10 oil, B34- and B128-based drilling fluids (T = 80 °C; a) P = 1 bar; b) P = 390 bar).

Experimental and estimated viscosities, using FMT, Yasutomi and WLF-Barus models, for SR10 oil and drilling fluids, as a function of pressure, at 80 °C.

The first documented spring-pole well in America was drilled in 1806 by David and Joseph Ruffner in West Virginia. It reached 58 feet in depth, containing 40 feet of bedrock. The project lasted two years.

A patent to L. Disbrow for the first four-legged derrick was given, originally in 1825 and then elaborated on in 1830. The structure consisted of legs made of square timber wood. The girts were mortised and inserted into the wooden legs with keys so the structure could be dismantled.

Men in Kentucky were drilling an exploratory well for salt brine. Instead, they hit an oil well. The pressure of the gas and oil underneath the surface forced an enormous geyser into the air. This was noted to be America’s first oil well (although there are some disputes to this claim).

J.J. Couch invented the first mechanical percussion drill, which he later perfected with the help of fellow inventor J.W. Fowle. Steam was admitted alternately to each end of a cylinder. The drill was thrown like a lance at the rock on the forward stroke, caught and then drawn back on the reverse stroke, and then thrown again. It was the first drill that did not depend on gravity. It went to work on the Hoosac Tunnel project, which bored a passage for trains through hills near North Adams, Mass.

George Bissell and Edwin L. Drake made the first successful use of a drilling rig on a commercial well drilled especially to produce oil in Pennsylvania. They drilled to 69 feet.

In June, J.C. Rathbone drilled a discovery well to 140 feet using a steam engine on the banks of the Great Kanawha River in the Charleston, W.Va., area. The well produced about 100 barrels of oil a day.

Charles Burleigh, John W. Brooks, and Stephen F. Gates patented a mechanical drill meant to be used on the Hoosac tunnel: the compressed air Burleigh drill. The tunnel spurred several innovations in drilling technology, including the earlier Couch/Fowle drill.

Edward A.L. Roberts was awarded a patent in November 1866 for what would become known as the Roberts Torpedo, a device for increasing the flow of oil by using an explosion deep in a well. The new technology revolutionized the young oil and natural gas industry by increasing production from individual wells.

Simon Ingersoll received a patent for a rock drill on a tripod mount. The drill was designed for mining and tunneling. It enabled the operator to drill at virtually any angle. He formed Ingersoll Rock Drill to capitalize on this invention, a company that is a precursor to Ingersoll-Rand.

The Bucyrus Foundry and Manufacturing Company was founded in Bucyrus, Ohio. The company later became famous in the drilling industry as Bucyrus-Erie, a maker of cable-tool rigs, but it was an early producer of steam shovels. It supplied many of the steam shovels used in the building of the Panama Canal.

Edmund J. Longyear drilled the first diamond core hole in the Mesabi Iron Range (shown above in 1903) in northern Minnesota. Shortly thereafter, he formed a contract diamond drilling company to serve the rapidly growing U.S. iron ore mining and steel industry.

John Smalley Campbell issued the first U.S. patent for the use of flexible shafts to rotate drilling bits. The patent was for dental applications, but was broad enough to cover larger scales, such as those used now in horizontal oil wells.

The Baker brothers were using their rotary method for oil well drilling in the Corsicana field of Navarro County, Texas. Their rig was powered by a mule.

Drillers at Spindletop, including brothers Curt and Al Hamill and Peck Byrd, noticed that muddied-up freshwater could help stabilize a formation and prevent borehole collapse. They started circulating it and drilling mud was born.

Captain Anthony F. Lucas at Spindletop began drilling with a steam-driven rotary rig and a double-pronged fishtail bit. The gusher at Spindletop lasted nine days and ushered in the first Texas oil boom.

Inspired by the success of Spindletop and what it meant for the future of oil drilling in Texas, Howard Hughes Sr. and Walter Sharp founded the Sharp-Hughes Tool Company. The Hughes name lives on today in the name of the company Baker-Hughes.

Edmund J. Longyear and John E. Hodge formed Longyear & Hodge, the manufacturing partnership that would eventually evolve into Boart Longyear. The company"s early drills were steam powere