TY - JOUR
AU - Qin,, Han
AB - Abstract Wellbore instability is one of the major problems hampering the drilling speed in the Fergana basin. Comprehensive analysis of the geological and engineering data in this area indicates that the Fergana basin is characterized by high in situ stress and plenty of natural fractures, especially in the formations which are rich in bedding structure and have several high-pressure systems. Complex accidents such as wellbore collapse, sticking, well kick and lost circulation happen frequently. Tests and theoretical analysis reveals that the wellbore instability in the Fergana basin was influenced by multiple interactive mechanisms dominated by the instability of the bedding shale. Selecting a proper drilling fluid density and improving the sealing characteristic of the applied drilling fluid is the key to preventing wellbore instability in the Fergana basin. The mechanical mechanism of wellbore instability in the Fergana basin was analysed and a method to determine the proper drilling fluid density was proposed. The research results were successfully used to guide the drilling work of the Jida-4 well; compared with the Jida-3 well, the drilling cycle of the Jida-4 well was reduced by 32%. bedding shale, wellbore instability, creep, permeability, drilling fluid density, borehole shrinkage 1. Introduction The Fergana basin is rich in oil and gas resources. Currently, its ultimate recoverable reserve of oil is estimated as 40 × 108 t, with just a quarter already proven, so this basin is of a high potential capacity (Khain et al1991, Zhu et al2005). The Fergana basin is located in the west of the Tianshan Fold System and the basin between the middle and southern Tianshan Mountain. The Fergana basin is an intermountain basin with a north-to-west strike direction. The centre of the Fergana basin is in Uzbekistan; the east and south-west of the basin separately belong to Kyrgyzstan and Tajikistan (figure 1). The area of the Fergana basin is about 38 000 km2. Figure 1. Open in new tabDownload slide The location of the Fergana basin. Figure 1. Open in new tabDownload slide The location of the Fergana basin. Maintaining wellbore stability is an important issue in the oil and gas industry. In the process of drilling, the economic losses caused by wellbore instability reach more than one billion dollars every year, and wellbore instability accounts for over 40% of the non-productive drilling time. Drilling in the Fergana basin is especially difficult—the engineering scrapped rate of the drilled wells is up to 55% (Zhou et al2011), which has seriously hampered the oil exploration and development process in Fergana basin. The Kalajida Structure is a cogent example: the K-1 well and K-2 well were both abandoned because of wellbore instability. The drill pipe stuck three times and a side-tracked hole was drilled during the drilling process of the K-1 well; the drill pipe stuck ten times and five side-tracked holes were drilled during the drilling process of the K-2 well. Although the following drilling of the Jida-3 well was successful, complex accidents such as drill pipe and instrument sticking also happened frequently. It was difficult to increase the drilling speed, which seriously delayed the exploration and development progress. So resolving wellbore instability problems becomes a key to boosting the drilling speed. 2. Geological and engineering features in the Fergana basin 2.1. Geological characteristics The Fergana basin has experienced complex geological evolutions such as tectonic uplift, tensile thermal subsidence and compressional orogeny. Especially after the Miocene, the Fergana basin experienced orogenic compression as well as strike slip motion, so the geological conditions are very complex and many faults developed (Bazhenov 1993, Simon 1997, Zhu et al2005, Zhou et al2011). There are highly fractured zones near the faults and on the high focus of the structure. The depositional sequences from top to bottom are, successively, Q-N2, N1-BPC, N1-KKC, E3, E2, E1 and Q-N2 formations. The N1-BPC formation is principally composed of sandstone and shale. The lithology below the N1-KKC formation is complicated by interbedded sandstone, shale, limestone and salt rock. The mineral components of the shale formations are mainly illite/smectite mixed-layer and illite. An approximately horizontal bedding plane is developed in the shale formation. The target layers are in the lower part of the N1 formation and the upper part of the E formation, and the depth range is 5700–6500 m. The pore pressure system is complex below the N1-KKC formation. There are multilevel high-pressure brine-water layers and a maximum pore pressure coefficient as high as 2.35. Logging information shows that the acoustic wave and the density are abnormal: the acoustic travel time is high and the density is low, which indicates an undercompaction mechanism of overpressure. 2.2. Drilling situations The geological characteristics in the Fergana basin determine that the wellbore stability deserves great attention in the drilling process. The history of the drilling operation in the Fergana basin dates back to the former Soviet Union period. Both the K-1 well and K-2 well failed for technical reasons. The K-1 well and K-2 well used a casing program with four spud sections, and resulted in frequent accidents of failing due to the separate complicated formations. The Jida-3 well used a casing program with five spud sections, but the third spud was not deep enough (4800 m) to separate the normal pressure formation (5711–5778 m) and the high pressure formation (below 5792 m), which caused a series of accidents. During the drilling process of the Jida-3 well, a zwitterionic polymer drilling fluid system was used in the first spud, a zwitterionic KCl polymer drilling fluid system was used in the second spud and a zwitterionic KCl polysulfonate drilling fluid system was used after the third spud. But the drilling process after the third spud experienced many problems such as serious borehole shrinkage and collapsing, which demonstrated that the zwitterionic KCl polysulfonate drilling fluid system maybe not suitable for this field. Frequent sticking when tripping and lost circulation dominated the complex accidents of drilling in the Fergana basin. The drilling experience indicates that purely increasing the drilling fluid density is not an effective method to resolve wellbore instability, and that the drilling fluid property also plays an important role in retaining wellbore stability. The NO 14 well in the Fergana basin lost circulation due to the high drilling-fluid density, which then caused the fluid pressure to decline to lower than the pore pressure, which finally lead to a blowout accident. The drilling cycle of the K-1 well was 949 days, and it experienced three stickings and one sidetrack. The drilling process of the K-2 well lasted for 6 years, and it experienced 10 stickings, five drops and five sidetracks. The Jida-3 well's drilling cycle was 496 days, and it experienced two stickings and three sidetracks. It was difficult to deal with the downhole accidents in the Fergana basin, which were prone to inducing sticking accidents. Unfreezing was difficult once sticking happened. The wellbore collapsed seriously in the process of dealing with the accidents, which made unfreezing more and more difficult, and frequently caused well abandonment. 3. Wellbore stability analysis in the Fergana basin One of the purposes of researching wellbore stability is to accurately reveal the wellbore instability mechanism and to provide some technical support for a safe and efficient drilling operation (Roegiers 2002). The particular geological characteristics of the Fergana basin suggest that the wellbore instability is caused by multiple mechanisms and their interaction. Overall, the bedding shale is distributed extremely widely in the Fergana basin. The highly fractured zone, the salt rock and the plastic gypsum mudstone are only present at some partial formations. So the wellbore instability of the bedding shale is the main factor causing drilling problems, and downhole leakage is mainly induced by formation fracturing due to a high bottom hole pressure difference. 3.1. Collapse of bedding shale For the Fergana basin, the wellbore stability of the bedding formation is the key to solving the wellbore instability of the fracture zones, is a prerequisite of the effective effort into drilling improvement in the salt rock and the plastic gypsum mudstone, and is also an effective way to solve the lost-circulation problems. 3.1.1. Experimental study on the permeability of bedding shale The permeability characteristics of the bedding shale of the E3 formation in the Fergana basin were tested on a conventional triaxial test cell. Two kinds of standard core samples (φ 25 mm × 50 mm) were prepared in order to test the influence of the bedding plane on the permeability. The axis of one kind of cores was parallel to the bedding plane and that of the other kind was perpendicular to the bedding plane. The test results are shown in table 1, from which the following conclusions can be drawn. Table 1. Test results of the permeability of the bedding shale. Cores number . Coring way . Confining pressure (MPa) . Fluid driving pressure (MPa) . Permeability (10-9 µm2) . 1–1 ⊥ 5 3   17.8 1–2 = 5 3   55.1 1–3 = 5 3 3138.6 2–1 ⊥ 5 3   37.2 2–2 = 5 3  248.6 2–3 = 5 3   97.7 3–1 ⊥ 5 3   27.8 3–2 = 5 3 2862.0 3–3 = 5 3 2179.5 Cores number . Coring way . Confining pressure (MPa) . Fluid driving pressure (MPa) . Permeability (10-9 µm2) . 1–1 ⊥ 5 3   17.8 1–2 = 5 3   55.1 1–3 = 5 3 3138.6 2–1 ⊥ 5 3   37.2 2–2 = 5 3  248.6 2–3 = 5 3   97.7 3–1 ⊥ 5 3   27.8 3–2 = 5 3 2862.0 3–3 = 5 3 2179.5 Note: ⊥ means perpendicular to the bedding plane; = means parallel to the bedding plane. Open in new tab Table 1. Test results of the permeability of the bedding shale. Cores number . Coring way . Confining pressure (MPa) . Fluid driving pressure (MPa) . Permeability (10-9 µm2) . 1–1 ⊥ 5 3   17.8 1–2 = 5 3   55.1 1–3 = 5 3 3138.6 2–1 ⊥ 5 3   37.2 2–2 = 5 3  248.6 2–3 = 5 3   97.7 3–1 ⊥ 5 3   27.8 3–2 = 5 3 2862.0 3–3 = 5 3 2179.5 Cores number . Coring way . Confining pressure (MPa) . Fluid driving pressure (MPa) . Permeability (10-9 µm2) . 1–1 ⊥ 5 3   17.8 1–2 = 5 3   55.1 1–3 = 5 3 3138.6 2–1 ⊥ 5 3   37.2 2–2 = 5 3  248.6 2–3 = 5 3   97.7 3–1 ⊥ 5 3   27.8 3–2 = 5 3 2862.0 3–3 = 5 3 2179.5 Note: ⊥ means perpendicular to the bedding plane; = means parallel to the bedding plane. Open in new tab The permeability perpendicular to the bedding plane is extremely low and can almost be neglected. The permeability parallel to the bedding plane fluctuates distinctly, and has the following two characteristics: being concordant with the permeability perpendicular to the bedding plane, or being much higher than it. The main reason that the permeability parallel to the bedding plane is much higher than the one perpendicular to the bedding plane is probably that the bedding formation has lots of interlayer microcracks. The interlayer microcracks are distributed randomly so that some of the testing samples have a high permeability while other testing samples have a low permeability. In order to know the influence of the confining pressure on the permeability of the bedding plane, the permeabilities of core samples in table 1 were tested under different confining pressures. The test results of sample 1–3, 3–2 and 3–3 are shown in figure 2; we can see that the permeability under a low confining pressure decreases linearly with the increase in confining pressure, which agrees with the formula presented by Snow (1966). When the confining pressure increases to a certain value, the confining pressure closes the microcracks, and the permeability parallel to the bedding plane would be similar to the one perpendicular to the bedding plane. In this case, an increasing confining pressure has almost no influence on the other five samples. This indicates that the change in the confining pressure mainly impacts the permeability of the bedding plane. Figure 2. Open in new tabDownload slide The confining pressure's influence on the permeability of the bedding plane. Figure 2. Open in new tabDownload slide The confining pressure's influence on the permeability of the bedding plane. 3.1.2. Impact of seepage on the bedding-plane strength Based on the permeability characteristics of bedding shale, we assume that: seepage only happens in the bedding plane and just affects the mechanical property of the bedding plane; and that the effect of seepage on the mechanical property of the rock matrix is negligible. Therefore, experimental study of the seepage of drilling fluid and its effect on the mechanical property of the bedding plane is necessary. The experiment was divided into two processes: the processes of seepage along the bedding plane, and a strength test of the bedding plane. The test steps were as follows: firstly, cored samples parallel to the bedding plane were prepared as standard. Then they were placed into the permeability test equipment and the confining pressure and axial stress were set. A fluid driving pressure was applied to one end of the samples. If the sample has good permeability, it was filtrated for a specified time. If not, the core sample is exchanged for another one and the above steps are repeated. The bedding plane strength after infiltration is measured by the direct shear test. The direct shear test equipment and its operating principles are shown in figure 3. Figure 3. Open in new tabDownload slide Diagram of the direct shear equipment: (1) positioning bolt hole, (2) immobile indenter, (3) mobile indenter, (4) piston connected with hand-held pump, (5) mobile indenter connected to the jack, (6) core sample, and (7) base frame. Figure 3. Open in new tabDownload slide Diagram of the direct shear equipment: (1) positioning bolt hole, (2) immobile indenter, (3) mobile indenter, (4) piston connected with hand-held pump, (5) mobile indenter connected to the jack, (6) core sample, and (7) base frame. In this experiment, the bedding shale samples were taken from the E3 formation, and the on-site drilling fluid filtrates were used as the filtrating media. The bedding-plane strength mainly has two parameters: the cohesion and the internal friction angle. In order to determine these two parameters, two samples were tested after the same seepage time. Assuming the normal stress of the two tests on the bedding plane were σn1 and σn2 respectively, and the shear strengths of the core samples were τ1 and τ2, then the cohesion τj and internal friction angle φj of the bedding plane are as follows: φj=tg-1τ2-τ1σn2-σn1τj=τ1-σn1tgφj.1 The core samples’ direct shear strengths after different filtrating times were tested with the method mentioned above. The variations in the cohesion and the internal friction angle of the bedding plane with filtering time are shown in figures 4 and 5. The following conclusions can be reached from the experimental results. Figure 4. Open in new tabDownload slide The variation of the bedding plane's cohesion with seepage time. Figure 4. Open in new tabDownload slide The variation of the bedding plane's cohesion with seepage time. Figure 5. Open in new tabDownload slide The variation of the bedding plane's internal friction angle with seepage time. Figure 5. Open in new tabDownload slide The variation of the bedding plane's internal friction angle with seepage time. The seepage of the drilling fluids along the bedding plane decreases the cohesion and the internal friction angle of the bedding plane, which leads to the presence of a shear displacement on the bedding plane under a small shear stress. The variations of the bedding plane's cohesion and internal friction angle with seepage time are generally similar. This can be divided into three phases: a slowly declining phase, a rapidly declining phase and a smoothly declining phase. For bedding shale, the permeability of the bedding plane is much higher than that of the matrix. After drilling, the drilling fluid will quickly penetrate into the formation along with the bedding plane preferentially. This process leads a decrease in bedding-plane strength. Because the formation strength is dominated by a weak bedding plane, shear failure generally occurs along the bedding plane. The collapse blocks are large and have obvious structural planes (as shown in figure 6). Moreover, a small shear displacement on the highly penetrative bedding plane happens easily, which will lead to frequent reaming and back reaming, easily sticking because of collapsing caused by the bit's commotion. With the appropriate research results of (Mclellan and Cormier 1996, Yamamoto et al2002) and the results of actual observation (figure 6), we can find that the drilling fluid seeps along the high penetrative bedding plane under the drive of the bottom hole pressure difference. This process leads to a decrease in the effective normal stress on the bedding plane and thus the shear strength of the bedding plane. Then the formation around a wellbore will slide into the well, resulting in borehole shrinkage or dislocation and eventually the periodical collapse of the wellbore. Figure 6. Open in new tabDownload slide Photograph of collapse blocks of bedding shale. Figure 6. Open in new tabDownload slide Photograph of collapse blocks of bedding shale. 3.1.3. Wellbore stability model of bedding formation We regard the bedding formation as transversely isotropic and elastoplastic material which is anisotropic penetrated. Assuming the formation is continuous, the dynamic change in pore pressure has little effect on the wellbore stability and the deformation process of the rock skeleton can be considered to be quasi-static, so the force equilibrium equation around a wellbore can be written as (Xu 1998): σij,j+fi=02 where σij is the stress component around the wellbore and fi is the body force. The Biot's effective stress theory is expressed as follows: σij=σij′+αpδij3 where σij′ is the effective stress component around a wellbore, α is the Biot's coefficient, p is the pore pressure, and δij is the Kronecker symbol. Because of the pressure difference between the drilling fluid pressure and the pore pressure, the drilling fluid and its filtrate will flow into the formation. Assuming the seepage follows Darcy's law, according to the continuity equation, the distribution rule of pore pressure around a wellbore can be expressed as: 1μ∇·K∇p=1Π∂p∂t4 where μ is the viscosity of the drilling fluid and its filtrate, ∇ is the Hamilton operator, Π is a parameter related to the compression characteristics of the formation frame and pore, and [K] is a second-order tensor of permeability. Because the seepage mainly happens on the bedding plane, referencing Romm's derivation (Romm 1966), the permeability tensor can be written as K=Ke1-a1a1-a1a2-a1a3-a1a21-a2a2-a2a3-a1a3-a2a31-a3a35 where Ke is the bedding plane's permeability, and a1, a2, a3 are the direction cosines between the bedding plane normal and the wellbore rectangular coordinate system. Under the condition of small deformation, the relation between the strain and the displacement of rock is determined by the following geometrical equation: ɛij=12ui,j+uj,i6 where εij is the strain component and ui is the displacement component. Determining the constitutive equation is the basis of researching the law of deformation and the failure of a borehole. Considering the nonlinear influence caused by shearing sliding of the bedding plane, the incremental form of the stress–strain relation is as follows: {dσ′}=[D ep ′]{dɛ}7 where {dσ′} is the increment of the effective stress component, {dε′} is the increment of the strain component, and [D ep ′] is the matrix of the elastoplastic constitutive relation of transversely isotropic material, and its specific form is relevant to the yield function and the plastic potential function of the formation. If the formation dose not yield, namely it is in an elastic state, then: [D ep ′]=[D′]=M1-nν22ν1+nν221-nν22ν21+ν1ν21+ν11-ν22n000G1MG2MG2M8 In which M=E1/1+ν11-ν1-2nν22n=E2/E1G1=E1/21+ν19 where [D′] is the matrix of elastic constitutive relation of a transversely isotropic material, and E1, E2, ν1, ν2, G2 are five independent elastic parameters of a transversely isotropic material, which can be determined by Goodman's method (Goodman 1976). The yield function and plastic potential function of the bedding formation can be determined by the suggestion of Zheng and Hu (Zheng et al2002, Hu et al2004) about rock mass with a weak plane: f=g=τ ns 2+τ nt 2+tgϕj·σn-τj10 where f is the yield function of the bedding formation, gis the plastic potential function of the bedding formation, and τns, τnt, σn are separately the shear stress and normal stress on the bedding plane. If the formation is in a plastic state, the matrix of the elastoplastic constitutive relation of transversely isotropic material can be written as (Yu 2006): [D ep ′]=[D′]-[D′]∂f∂{σ′}∂f∂{σ′}T[D′]∂f∂{σ′}T[D′]∂f∂{σ′}+A11 where A is the hardening function. 3.1.4. Analysis Based on the above formulas and in situ stress data of the Fergana basin, stress and deformation around a wellbore in the bedding formation can be analysed. The calculation model takes into consideration the influence of the bedding plane's nonlinear characteristic and the bedding plane seepage. Figure 7 shows the relationship between the maximum borehole shrinkage rate and the borehole's open time. The calculation results indicate that the maximum borehole shrinkage increases slowly with the drilling time increasing in a very short time after drilling. After a period of time, this value increases quickly with the increasing in drilling time. And then, the increasing rate of maximum borehole shrinkage slows down and finally becomes smooth. Figure 7. Open in new tabDownload slide Variation of the maximum borehole shrinkage with borehole drilling time. Figure 7. Open in new tabDownload slide Variation of the maximum borehole shrinkage with borehole drilling time. For a hard brittle bedding formation, even if the borehole shrinkage is small, it has a serious effect on wellbore stability. The bit will create a downward push power on the borehole shrinkage formation during descent, which will cause formation collapsing under the bit, and this may not cause serious sticking. When being extracted from the hole, the bit creates an upward push power that leads to formation collapsing above the bit, which makes pulling the pipe difficult and may even cause sticking. If the drilling fluid density is too low, the shear failure of the bedding plane or rock matrix will occur on the wellbore wall (Aadnoy and Chenevert 1987). If the drilling fluid density is too high and the sealing characteristic is not good enough, the drilling fluid will flow into the formation along with the bedding plane, leading to the reduction of the effective stress on the bedding plane and the bedding-plane strength, and eventually the presence of shear failure on the bedding plane (Santarelli et al1992). Therefore, purely increasing the drilling fluid density is favourable to prevent borehole shrinkage over a short time, but the increase in the pressure difference between the drilling fluid pressure and the pore pressure will aggravate the seepage of the drilling fluid into the formation. With the borehole open time increasing, the pressure difference will be negative to prevent the borehole shrinkage (as shown in figure 7). Proper drilling fluid density and good sealing characteristics are the key to retaining wellbore stability in the bedding formation. To know the influence of drilling fluid sealing characteristics on borehole shrinkage, assuming the drilling fluid densities are the same and the seepage velocities on the wellbore wall are different, the time span during which the wellbore can retain stability is calculated, with 2% as the maximum hole shrinkage rate (Ewy's criterion (Ewy 1993): when the wellbore shrinkage rate exceeds 2%, it will influence the safety of drilling). The relationship between the wellbore stability time and the seepage velocity is shown in figure 8. Figure 8. Open in new tabDownload slide Relationship between wellbore stability time and seepage velocity. Figure 8. Open in new tabDownload slide Relationship between wellbore stability time and seepage velocity. Figure 8 shows that there is an exponent relationship between seepage velocity and wellbore stability time. The seepage velocity has a great influence on the wellbore stability time. When the seepage velocity is very small, the stability time is really long. With the increase in the seepage velocity, the stability time reduces sharply. When the seepage velocity rises over a certain value, the wellbore stability time is very short and cannot ensure safe drilling. From above analysis, it is clear that purely increasing the drilling fluid density cannot solve the wellbore instability problems in the Fergana basin. Improving sealing characteristics to control seepage velocity with a proper drilling fluid density is the key to preventing wellbore instability in the Fergana basin. 3.2. Shear failure of highly fractured formation The Fergana basin has experienced strong tectonic movement which created crisscrossed joints near the faults and the structural highs. The mechanical properties are completely controlled by the joint planes if the joints are crowded, so the strength of the rock mass is extremely low. To maintain the wellbore stability and avoid the shear failure of the rock mass, the drilling fluid density cannot be too low. In this situation, we can treat the formation as a highly fractured zone and the joint plane as a good seepage path (Santarelli et al1992, Labenski et al2003). The drilling fluid will seep along the joint plane if the sealing characteristics of the drilling fluid are not so good, which will cause a decrease in the joint plane strength as well as the valid support of the fluid pressure to the wellbore wall, and will eventually lead to collapsing and sticking. In addition, the joint plane on the wellbore wall will be opened if the drilling fluid pressure is too high (Helstrup et al2003, 2004), and it will cause a little slippage of the wellbore with potential hazards, namely shear displacement. This is the main cause of wellbore instability in fractured zones. Borehole failure mainly happens at the maximum horizontal principal stress direction in highly fractured zones, and the dual caliper curves show that the major axis of the borehole comes back to the normal condition (Yu et al2007). Unlike the bedding formation, the collapsed blocks of fractured zones have no apparent preponderance plane and are approximately massive bodies (Ottesen 2010), which are very small and have apparent sharp-pointed angular edges (as shown in figure 9). Figure 9. Open in new tabDownload slide Photograph of high fractured formation. Figure 9. Open in new tabDownload slide Photograph of high fractured formation. 3.3. Creep of salt rock Salt rock is present in the N1-KKC formation of the Fergana basin. The prominent feature of salt rock formation is its tendency towards plastic deformation after drilling. During the drilling process it reflects as borehole shrinkage, drill pipe sticking and casing sticking (Barker et al1994, Fredrich et al2003). Stresses in the salt rock formation of the Fergana basin are relatively high and the temperature is relatively low (less than 250 °C). So the creep is controlled by a dislocation sliding mechanism. The constitutive equation of creep can be depicted using Heard's creep constitutive equation (Heard 1976, Deng 1997): ɛ̇=A exp (-Q/ RT ) sh (Bσ)12 where ɛ̇ is the steady-state creep rate, Q is the activation energy, R is the mol gas constant, σ is the deviatoric stress, T is the absolute temperature, and A and B are the rheological constants. According to the drilling and logging data of the salt rock formation in the Fergana basin, the creep parameters were ascertained using the engineering inversion theory (Lin et al2005): A is 3.47, B is 0.13, and Q is 14.28 × 104 J mol-1. The drilling fluid density is the only artificially controllable factor to prevent borehole shrinkage in a salt rock formation (Carcione et al2006). Excessive density will cause the weak layer to fracture and will result in formation pollution and lost circulation. On the other hand, low density will cause pernicious accidents such as borehole shrinkage and sticking. So the law of borehole shrinkage under different drilling fluid densities needs to be studied. The laws of borehole shrinkage in salt rock formations in the Fergana basin under different drilling fluid densities are calculated using the geologic data and the inversed creep parameters (Deng 1997). The calculation results are shown in figure 10. Figure 10. Open in new tabDownload slide Borehole shrinkage under different drilling fluid densities in salt rock. Figure 10. Open in new tabDownload slide Borehole shrinkage under different drilling fluid densities in salt rock. 3.4. Hydration and borehole shrinkage of gypsum mudstone Many gypsum mudstone formations are drilled after drilling into the N1-KKC formation in the Fergana basin. On the basis of the formation's physical and chemical properties, this type of formation is easy to be water swelled and dispersed (Mao et al2010), which makes the formation soft and leads to borehole shrinkage or collapsing. From the perspective of rock mechanics, this type of formation belongs to viscoelastic plasticity material, and elastoplastic deformation will appear while drilling. After drilling, continuous deformation will result in downhole accidents such as borehole shrinkage and collapse (Cheng et al2007). For example, drill pipe and logging tools were stuck for many times in the Jida-3 well and its side tracked hole in the gypsum mudstone formation at 5740 m. The reasons why these accidents happened are closely related to the drilling fluid density and filter loss, but the main reason is that the drilling fluid's chemical characteristics are not compatible with the formation. 4. Case study The Jida-4 well is anther exploration well after the drilling of the Jida-3 well in the Fergana basin, and is deeper than the Jida-3 well. A casing program with five spud sections was applied to the Jida-4 well. A zwitterionic polymer drilling fluid system (in the first and second spud) and a NaCl polysulfonate drilling fluid system (after the third spud) were used in drilling. The third spud section ran to 5157 m, which is deeper than the Jida-3 well with an optimization. Figure 11 shows the logging data and uniaxial compressive strength (UCS) of the Jida-4 well. The formation strength near the well bottom changes sharply. The wellbore stability of the Jida-4 well is evaluated (as shown in figure 12) based on the above research. The following aspects are highlighted to evaluate the safe mud weight window: (1) for bedding formations which are mostly prone to wellbore instability, the drilling fluid density firstly should be high enough to ensure a borehole shrinkage rate of no more than 2% to prevent shear slip along the bedding plane. The fluid pressure should not be low enough to ensure the effective stress perpendicular to the bedding plane is compressive. (2) For highly fractured zones, the drilling fluid density is calculated with the application of an equivalent continuum model with reduced parameters to prevent the shear failure of the rock mass around the wellbore. The drilling fluid pressure must be less than the minimum horizontal stress to ensure the joint plane is in a compressive and closed state. (3) The creep shrinkage problem of salt rock can be resolved by adjusting the drilling fluid density and strengthening the reaming operation in the drilling process to make sure the borehole shrinkage between two reaming operations can not affect the pipe trip. (4) The shrinkage problem of gypsum mudstone could be resolved by improving the chemical compatibility between the drilling fluid and the formation. The reaming operation should also be strengthened. The drilling fluid density is calculated using an elastoplastic model without considering the impact of formation rheology and hydration. Figure 11. Open in new tabDownload slide Logging data and formation strength of Jida-4 well. Figure 11. Open in new tabDownload slide Logging data and formation strength of Jida-4 well. Figure 12. Open in new tabDownload slide Pressure evaluation of the Jida-4 well. Figure 12. Open in new tabDownload slide Pressure evaluation of the Jida-4 well. As shown in figure 10, the highest values of pore pressure and collapse pressure below the E3 formation in the Jida-4 well both reach more than 2.35 g cm-3. The narrowest part of the safe mud weight window is only about 0.1 g cm-3. With regard to this, the Jida-4 well adopted measures of controlling the upper and lower limit of drilling fluid density strictly. The drilling fluid density was controlled to no higher than 2.4 g cm-3 and the sealing characteristic of the drilling fluid was strengthened. These measures effectively avoided accidents such as sticking, and serious borehole enlargement no longer occurred on the dual caliper curve. The drilling cycle of the Jida-4 well was 337 days, which was 159 days less than the Jida-3 well, and thus the drilling cycle reduced by 32%. Compared with the total depth of the Jida-3 well, the drilling time of the Jida-4 well was 235 days at the same depth, which was reduced by 53%. 5. Conclusions Wellbore instability in the Fergana basin was influenced by multiple interactive mechanisms which are dominated by the instability of bedding shale. Borehole shrinkage caused by a shear slip along the bedding plane in the bedding formation is the immediate cause for a stuck pipe during tripping. A highly fractured formation and drilling fluid seepage further exacerbate wellbore instability. For the bedding formation, the drilling fluid will flow into the formation along with the bedding plane, which will lead to a decrease in the bedding plane strength and the effective stress on the bedding plane, and will eventually cause shear failure on the bedding plane. The adverse effect of wellbore stability will increase with an increase in borehole open time. Although merely increasing the drilling fluid density is beneficial in retaining wellbore stability in the Fergana basin for a short time, the increase in pressure difference between the drilling fluid pressure and pore pressure will aggravate the seepage of the drilling fluid. With the borehole open time increasing, high-density drilling fluid will be negative to prevent wellbore instability. Improving the sealing characteristic of the drilling fluid and controlling the seepage velocity based on a proper drilling fluid density is the key to preventing wellbore instability in Fergana basin. The wellbore stability of the Jida-4 well was evaluated, and downhole accidents such as pipe-sticking were effectively avoided in filed application. The drilling cycle of the Jida-4 well was reduced by 32% compared with the Jida-3 well. 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TI - Wellbore stability analysis and its application in the Fergana basin, central Asia
JF - Journal of Geophysics and Engineering
DO - 10.1088/1742-2132/11/1/015001
DA - 2014-02-01
UR - https://www.deepdyve.com/lp/oxford-university-press/wellbore-stability-analysis-and-its-application-in-the-fergana-basin-VltClaaPpY
VL - 11
IS - 1
DP - DeepDyve
ER -