Introduction

Shale fractured reservoirs structures are often weak and can fall into the well that has caused to trap of the drill string in the well (Maneth Wanniarachchi et al. 2017). Moreover, the vibration of the drill string can cause such structures to collapse even in drilling with oil-based and synthetic-based mud. In these reservoirs, fluid may seep into the cracks, polishing the crack surfaces and equalizing the pore pressure to the well pressure (Zhang et al. 2020). This phenomenon quickly takes the well out of stability or blow out. This issue occurred in high-pressure, high-temperature (HPHT) wells. It is schematically drawn in Fig. 1.

Fig. 1
figure 1

Schematic drilling of a fractured shale reservoir

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Drilling fluid often has a temperature difference with the adjacent formation due to the ground temperature gradient (Amani et al. 2012). This causes temperature transfer between the two environments because the temperature expansion of water is much higher than the rock matrix. Therefore, the pressure difference between formation and drilling fluid corresponds to a further increase in the volume of the formation fluid from the rock matrix and thus increases the cavity pressure. In addition, increasing the volume of the rock matrix in limited conditions leads to thermal stresses in the formation. Decreased adequate mud support because of increased cavity pressure and thermal stresses creates more unstable conditions in the well. Conversely, cooling the formation reduces the cavity pressure and tangential stress, resulting in more stable well conditions (Wang et al. 1996). Reducing tangential stresses leads to decreasing hydraulic fracture pressure, but increasing cavity pressure and creating thermal stresses depend on thermal conductivity, specific heat capacity, poroelastic properties, shale permeability, volume coefficient, and shale temperature (Fig. 2).

Fig. 2
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Water activity for different fluid densities of various formate fluids

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Formate fluids have little water activity, thus producing an osmotic pressure that causes water to flow from the shale to the drilling mud, increasing the shale's stability (Zhang et al. 2008; Oort 2018). Potassium formate can also increase the stability of shales by an ion-exchange mechanism. Formative salts also reduce the solubility of salts in salt layers by drilling mud. Increasing the stability of shale layers is one of the main reasons; most companies use this mud in drilling operations (Gholami et al. 2018; Ali et al. 2020).

Versan Kok M. and Alikaya T. (2003) investigated the influence of polymer additives on the rheological properties of drilling fluids such as fluid loss, pH, and filtration cake. It was observed that polymers could effectively improve drilling fluids' rheological properties, especially in shale reservoirs. Safi. B et al. (2016) investigated the impact of polyanionic cellulose and polyanionic cellulose on the drilling fluids’ rheological properties based on water. They observed that these two polymers would enhance water-based drilling fluid's rheological properties and be used as a proper drilling fluid for well operations (Safi et al. 2016). In this study, we experimentally investigated polymer-based drilling fluids such as cellulose polyanionic (PAC) and cellulose polyanionic-ultralow (PAC-UL) and how they affect rheological properties. This study was based on the following sections sequentially. After a brief introduction about the effectiveness of polymer-based drilling fluids and how it affects the rheological properties, in “Materials and methods” section, the materials and methods used in this experiment are in more detail. Then, in “Experimental results” section, experimental results contained water activity, the effect of polymers on the rheological properties, and then the shale recovery results were discussed. In the final section, the main findings of this study were reported briefly to focus more on the importance of polymer impact on the improvement of rheological properties.

Materials and methods

Drilling salty layers with conventional mud first dissolves the salt in the mud and, as a result, creates a washout. Second, dissolving the salt in the mud can change the rheological properties of the drilling mud. Formate fluids reduce the tendency of salt to dissolve in drilling mud. Dissolution of a small amount of salt in the drilling fluid does not cause a significant change in the rheological properties.

Materials

The selected drilling fluid for fractured shale must have the most suitable chemical composition to have minimal effect on the formation. The chemical design of drilling fluid should be implemented to control smooth penetration and mud pressure into the formation by balancing the activity of mud water with the activity of water formation. Moreover, it can create very high capillary pressure, reducing damage to tanks, increasing stability against mixing due to electrolytes, increasing stability.

Physical design of drilling fluid

The physical design of drilling fluid has been performed to adjust the weight of drilling fluid and provide the appropriate compressive force applied to the formation, preventing the transfer of water from the drilling fluid to the shale by using cavity blocking additives on the surface the formation. Moreover, it can create suitable rheology for drilling fluid and ultimately reduce formation damage. The applied compressive force can prevent the shales from swelling. Some of the laboratory properties of the rock can be used as a basis for determining the weight of the mud and preventing the failure or plastic behavior of the shale. Formate fluids are salts derived from formic acid (an organic substance found in nature, including trees, plants, etc.). Formate fluid is a solution of alkaline metal salts derived from formic acid in water. These salts are well soluble in water and provide high-density salt solutions. The three types of formate salts most commonly used in the oil industry are sodium formate (NaCHOO), potassium formate (KCHOO), and cesium formate (CsCHOO). Formate anions are more hydrophilic than carboxylic anions and also retain good organic properties compared to halides. This property is observed in the solubility of formate salts in organic solutions such as methanol or ethylene glycol. (Zhang et al. 2008) Alkali (alkaline) metal salts show excellent solubility in water, and therefore, these salts can achieve specific gravity. Sodium formate has less solubility than the rest and can reach a specific gravity of about 1.4 SG (10.6 ppg). Potassium formate has more solubility than sodium formate and gives a maximum of 1.54 SG up to specific gravity (13 ppg), and cesium formate can give a maximum specific gravity (18.9 ppg) of 2.1 SG. Alkali metal cations (sodium, potassium, and cesium) are all monovalent, which gives them unique compatibility with biopolymers. The weight or molar percentage of their solubility in water at 20° C is shown in Table 1. (Zhang et al. 2008).

Table 1 Formate fluids properties
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Alkali metal salts in solution also exert a structural effect on the surrounding water molecules. This structural behavior of water has a favorable effect on the formation of soluble macromolecules and makes them more regular, stable, and stable against higher temperatures. Combining two antioxidant properties and water-structuring properties of formate salts gives them the ability to increase the maximum degree of heat stability for common polymeric fluids. For example, xanthan gum polymer, used as a viscosity agent, can be stable in formate solutions up to 180 °C/356 °C for 16 h. This can be increased to 204 °C/400 °C by adding some antioxidant chemicals (Zhang et al. 2008). Other properties of formate fluid are illustrated in Table 2. Mud type#1 is sodium formate fluid, mud type#2 is potassium formate fluid, and mud type#3 is the base mud.

Table 2 Formate fluid composition
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Methods

Particles from shale samples with sizes between sieves number 100 and 200 (sample should be dried at 150° F for 24 h) were selected. Then, 400 ml of the solution was put in the desiccator and placed the plate on top of it. Next, pour some of the prepared samples into a container and place them on the top plate of the solution. In order to drain the air and seal it, dip the edge of the desiccator with silicone base glue and put the lid on. After reaching the appropriate vacuum, the fluid boils and creates bubbles. This is due to the reduction of the pressure in the upper chamber of the fluid, and it is reaching the vapor pressure of the fluid. Daily, weigh the sample, return it to the desiccator, and weigh it again. Rheological properties such as apparent viscosity, plastic viscosity, and yield point of each sample were measured. After measuring the properties, the samples were heated at 250° F for 16 h, and their properties were measured again.

Experimental results

Water activity

Water activity is plotted versus fluid density for different formate fluids, indicating that water activity has higher values in the lower fluid densities and more shale stabilization. It was observed that by the increase in fluid density, water activity had been decreased slightly, which indicated that water contents in the drilling fluid replaced polymers.

Rheological properties

Table 3 shows the API fluid loss, plastic viscosity, apparent viscosity, yield point, and different mud types. As shown in Table 3, yield point and apparent viscosity for mud types# 1 and 2 are higher than mud type#3 as PAC-UL and PAC polymers were in their formulation. It indicates the effect of formate salts in increasing thermal stability. In addition, in mud type#1, more amounts of formate salts have been used, and it is observed that the fluid loss had lower.

Table 3 Rheological properties of different mud types
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Shale recovery test

To perform shale recovery test, after measuring the rheological properties of each sample and before heating them, for each sample, specific ions (smaller than mesh sieve 5 and larger than mesh sieve 10) were added and then heated them at 250 °C for 16 h according to API-13I standard at the rate of 20 g of shale sample with grain size. At the end of the heating operation, the samples are removed from the oven and after the temperature has decreased. According to the American ASTM standard, each sample is passed through a sieve with a mesh size of 35. This must be done very carefully. Then, the shale grains left on the sieve are washed with saturated salt water, and after complete washing, we put them in the dryer for 4 h and then weighed them again. The shale recovery rate of each sample is obtained from the following equation.

$${\text{Shale}}\,{\text{recovery}}\% = \frac{{{\text{Dried}}\,{\text{shale}}\,{\text{weigth}}\,\left( {{\text{gr}}} \right)}}{{{\text{Initial}}\,{\text{shale}}\,{\text{weight}}\,\left( {20{\text{gr}}} \right)}} \times 100$$
(1)

Figure 3 shows the shale recovery rate for potassium and sodium formate fluids at different concentrations of formate salts. The potassium formate fluid has provided a higher shale recovery rate than sodium formate fluid regarding its better inhibitory properties. Furthermore, it is observed that the shale recovery rate increases with increasing the concentration of formate salts.

Fig. 3
figure 3

Shale recovery test for two formate fluids

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Due to the higher cost of potassium formate than sodium formate, drilling fluid was made from the combination of sodium and potassium formate salt in a ratio of 50:50 (mud type # 4). The comparative properties of this combined fluid with the fluid containing 100 g of sodium formate are shown in Table 4. As shown in Table 4, the drop in fluid rheology properties in a fluid containing 100 g of sodium formate is more significant than in the other two samples. Moreover, for a fluid containing 100 g of potassium formate, the loss of rheological properties of the fluid is minimal.

Table 4 Rheological properties of different mud types
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Conclusion

Formate fluids are salts derived from formic acid (an organic substance found in nature, including trees, plants, etc.). Formate fluid is a solution of alkaline metal salts derived from formic acid in water. The following results are presented concerning formate fluids in drilling oil and gas wells according to the studies and experiments performed.

  • Formate fluids have a small amount of ECD because of the minimum solid particles in the mud system. Therefore, they have less pressure drop, and with this type of mud, deeper wells with smaller diameters can be drilled.

  • Sodium and potassium formate salts can give high-density fluids up to 90 PCF, and the solids percentage of these fluids is minimal.

  • The shale recovery rate for potassium formate fluids is higher than sodium formate fluid. In addition, the shale recovery increases with increasing the concentration of formate salts.