Dependency of Pressure Expression towards Formation Pressures during Drilling Operations in Hydrocarbon Wells and Suitable Choice of Pressure Control Method

Abstract

High pressures during drilling with the aim to obtain hydrocarbon formations (oil and natural gas) can cause an uncontrolled eruption. Therefore, it is necessary to look for warning signs of kicks and control the formation strength. The aim of this article is to show a real process of fracture pressures during a gas kick and their possible solutions. The evaluation of the lithological structure of formations and the correct evaluation of seismic measurements are closely related to the issue of fracture pressures. The contribution also includes software data for detailed analysis and calculations of formations pressures. We point out the incorrect calculation of the geological lithology and employ a casing shoe; it is a risky decision to use a formation integrity test as opposed to a leak of the test. Based on theoretical knowledge, we compared and verified the recalculation of pressure coefficients during the gas kick. In our case, we propose possible solutions for cracking a casing shoe. We point out the importance of correct calculations for a safe and economical purpose. In this post, a theoretical example was shown where the system of casings was correctly designed, and based on this, we obtained ideal values of the fracture pressures. In the end, we proposed an algorithm to simplify work procedures during well control to minimize formation pressures against the deposit and casing shoe.

1. Introduction

The principle and scheme of the hydrocarbon well were studied and modeled, on the basis of which it was possible to deduce the correct technological procedure for well control in the hydrocarbon well [1]. The global oil and gas market has been changing dynamically in recent decades. The development of non-conventional low-carbon energy sources on the global market is currently leading to the formation of not only supply, but also demand. The exploration and extraction of newly-discovered high-quality oil and natural gas deposits also contributes to this. There is no doubt that oil and natural gas represent a symbol of economic power in today’s world, and the vast majority of developed countries are dependent on this commodity. Therefore, jobs connected with the oil industry are especially important in countries with large sources of this mineral wealth. Of course, the frequency of these works also goes hand-in-hand with safety, which is always a top priority for the world’s leading companies. The biggest boom in drilling for oil and natural gas began at the turn of the 19th and 20th centuries, especially in the United States, when the then-successfully drilled deposits spewed out geysers of oil or gas, without any possibility of regulating this self-flow.

These circumstances, when huge amounts of oil escaped uncontrollably and very often resulted in loss of life, resulted in the creation of a completely new industry focused on the prevention of kicks and the elimination of eruptions. Myron M. Kinley invented a large number of methods, various preparations and devices, most of which are still used today, and Harry S. Cameron invented the pipe ram preventers [2,3,4,5,6,7]. Not all hydrocarbon deposits that are discovered are cost-effective [8,9].

Knowledge of minimum horizontal stress (Shmin) is important in many aspects during the life of oilfield development. It impacts all the development phases from well design to well abandonment. Shmin is a key factor for design of well trajectory and casing programs, and prediction of wellbore stability and lost circulation in the drilling and completion phases [10]. The finite difference method was adopted for solving mathematical equations [11,12]. For safe and efficient oil and gas extraction, the analysis of rock stress during induced seismicity monitoring is a necessary technological procedure [13,14,15,16].

Procedures of FIT or LOT are used extensively both for determination of the in situ formation stress for well barrier integrity assessment and for more general rock mechanical work such as quantifying fracture gradient for use in wellbore stability programs for drilling and completion operations [17]. During well control operations, the maximum allowable borehole fluid pressure at the casing shoe is normally considered to be the critical factor, based on the assumption that the weakest formation is at the casing shoe [18]. In this article, we point out the real course of the formations pressures during the gas kick in the well and their possible solutions. The data obtained from the project [19,20] must be analyzed and compared with theoretical knowledge, which will be confirmed by calculations. We have to find the thresholds (maximum values) for safe well control without the cracking of deposit rocks. Monitoring of rock fracturing pressures is generally necessary during hydrocarbon drilling operations. The citations given by us are related to the drilling issue. We point out the correctness of the predicted calculations, which can cause complications during drilling. We see a gap in the publications of later recalculations of strained pressure manifestations, so we draw attention to it.

2. Methods of Work

Study Area (Data Summary)

The average value of normal formation pressure may not be valid for all depths [19].

• Pressure Gradient

In the earth’s crust, there are sedimentary rocks, which are primarily filled with water as a result of sedimentation under normal circumstances. It can occur under normal or abnormal pressure. Also considered normal are those that are a multiple of the pressure head and the specific weight of the medium divided by 10.

The specific weight of water due to the degree of minimization can vary between 1.0 and 1.3 kg/L. Based on this, normal pressure gradients are those that vary between 0.10 and 0.13 at.m⁻¹. They are also referred to as hydrostatic pressure gradients. All pressure gradients below 0.10 at.m⁻¹ are sub-hydrostatic critical for deepening the earth’s crust, and pressure gradients above 0.13 at.m⁻¹ are super-hydrostatic pressure gradients and also critical. The designation normal pressure gradient is based on the idea that the water in the rocks with sufficiently permeable rock is under the influence of a pressure height that corresponds to the depth of the well. This pressure gradient must be considered as a consequence of sedimentation genesis. Sediments from the sea, such as sands and clays, first form a loose cluster on the seabed, which contain water in the interstices. As the sediments are moved further, the sediments are strengthened and a support structure is formed as a result of the overlying pressure. This compactness and reduction in the pore space leads to the necessity of a transferred portion of water.

• Hydrostatic and Hydrodynamic Pressure

The hydrostatic pressure of the water—deposit horizon with sufficient permeability (aquifer) would cause the rise of the water horizon in the emptied probe, which would act on its hydrostatic pressure. The height up to which the pressurized water in such probes, which are excavated in the same aquifer and are open to atmospheric pressure, rises or has risen is thought of as an equilibrium surface and is called the piezometric horizon.

This piezometric potential of water energy at each point of the aquifer surface rise and is not independent of the height of the aquifer.

Primary well control depends on drilling fluid of a sufficient extent densities and quantities.

That means hydrostatic the pressure in the wellbore is always higher than the fluid pressure in the formation in which the well is realized, but at the same time, lower than the fracture pressure of the formation. We can, thus, prevent the flow of liquids into the well.

Secondary well control—use of BOP to close the inflow to the well, then divert the inflow to surface and restore primary control conditions with proper procedures.

Tertiary well control is a kind of third defense system which is used if the well cannot be controlled using the two previous ones. For example, in the case of an underground eruption.

• Abnormal Formation Pressure

Abnormal formation pressures are those greater than the pressure exerted by a full column of formation fluid of normal weight. In most areas, the fluid considered to be of normal weight is formation salt water. Even though normal pressure is often expressed as 1.06 kg/L or 0.105 bar/m, which are, respectively, the density or the pressure gradient of the formation salt water, Figure 1.

Formation pressure categories:

Normal (hydrostatic), 1.06 kg/L–0.105 bar/m;

Abnormal—higher than normal;

Subnormal—lower than normal.

• Formation Fracture Pressure

Formation fracture pressure is the amount of pressure that causes a formation to break down, or fracture. In well control, the fracture pressure of the weakest formation exposed to the wellbore must be known, because the pressures developed during well-control procedures may exceed the fracture pressure of the formation.

Should fracture pressure be exceeded, the formation fractures, and lost circulation and an underground blowout or broaching could result [19].

Formation fracture pressure can expressed as:

-

Fracturing Pressure (bar);

-

Fracture gradient (bar/m);

-

Equivalent mud weight (kg/L).

• Formation Integrity Tests (FIT Test)

A leak-off test can also provide data for determining maximum allowable surface pressure (MAASP) at the most equivalent mud weight which can be used to avoid a casing shoe in front of a fracture pressure.

Since bottom hole pressure depends on mud weight, a change in mud weight changes MAASP; the higher the mud weight, the lower MAASP will be. Further, the test can indicate the competency of the cement bond at the shoe and whether remedial cementing or another string of casing may be required. To maintain a small safety factor to permit safe well control operations, the maximum operating pressure is usually slightly below the leak-off test result. The area of the graph bounded by the fracture pressure curve on the upper side and by the pore pressure curve on the lower side is often referred to and defined as the Drilling Operating Window, Figure 2.

Lithology effects:

-

The formation type will greatly influence the values of fracture gradient present in a well;

-

Some lithologies will exhibit elastic or plastic behavior, some rupture;

-

The magnitude of stress required to cause a formation.

• Leak-Off Test

Considerations before Conducting Leak-Off Test

Before a make leak-off test, we must drill out a casing shoe; 1 m to 15 m of hole should be drilled out below the shoe.

Since the mud’s gel strength, yield point, and viscosity affect the amount of pressure required to circulate it, it should be conditioned to reduce these values to a minimum. In particular, gel strength should be kept as low as possible, because it affects the amount of pressure needed to break circulation, and the pressure required to break circulation must be subtracted from casing shoe fracture pressure, Figure 3.

• Conducting Leak-Off Test

Many different techniques are available for running leak-off tests, most operators suggest using an accurate pressure gauge, cementing pump, which cannot exceed more than 80 L/min, and as it was mentioned, the shoe should not be drilled deeper than is required.

To conduct a leak-off test, the following is an accepted procedure:

(1)

Circulate the hole to have same mud density;

(2)

P/U a bit into the casing shoe;

(3)

Close the BOP;

(4)

Through the cement pump, pump down no higher than 80 L/min, and preferably at about 40 L/min;

(5)

On a graph, plot the fluid pumped in 40 L/min increments versus drill pipe pressure until the formation starts to take fluid, at this point, the pressure will continue to rise, but at a slower rate;

(6)

Repeat the test to verify the point at which the formation just starts to take fluid; this point is leak-off pressure.

By modifying leak-off pressure as necessary—such as by subtracting the amount of pressure required to break circulation—maximum allowable surface pressure can be determined.

• Maximum Allowable Mud Weight

The leak-off pressure (LOP) is the maximum surface pressure which the well could stand, with the hydrostatic head of mud in use at the time of the test.

The LOP plus the hydrostatic pressure of mud in use are equal to the formation fracture pressure as a formation strength in bar, which can be converted to Maximum Allowable Mud Weight (MAMW) [18].

$$\mathrm{MAMW} (\mathrm{kg}/\mathrm{L})=\frac{\mathrm{Surface} \mathrm{leak}-\mathrm{off} \mathrm{test} \mathrm{pressure} \left(\mathrm{bar}\right)\times 10.2}{\mathrm{Casing} \mathrm{shoe} \mathrm{depth}-\mathrm{TVD} \left(\mathrm{m}\right)}+\mathrm{Mud} \mathrm{Weight} \mathrm{in} \mathrm{hole} \left(\mathrm{kg}/\mathrm{L}\right)$$

(1)

• Maximum Allowable Annulus Surface Pressure (MAASP)

The LOP is the maximum surface pressure which the well could stand, with the hydrostatic head of mud in use at the time of the test. This can be described as the Maximum Allowable Annular Surface Pressure (MAASP) which belongs to that particular mud weight. Every time the mud weight is changed, the MAASP changes and must be re-calculated using Maximum Allowable Mud Weight [18].

$$\mathrm{MAASP} \left(\mathrm{bar}\right)=\frac{\mathrm{MAMWD} \left(\frac{\mathrm{kg}}{\mathrm{l}}\right)-\mathrm{Mud} \mathrm{Weight} \mathrm{in} \mathrm{hole} \left(\frac{\mathrm{kg}}{\mathrm{l}}\right)\times \mathrm{Casing} \mathrm{shoe} \left(\mathrm{m}\right)}{10.2}$$

(2)

A leak-off test is not usually a precise test, so, therefore, it is recommended to allow a safety margin, and record a lower formation fracture pressure. Companies have various margins, but the safety factor should be deducted from the formation breakdown pressure, and not from the MAASP, then the effect of the safety margin is being fully applied.

• Assessment of Teoretic Fracturing Pressure

Companies do not like to use theoretical calculations of formation pressures, but it is a good helper for designers of wells.

$$\mathrm{Hubber} \mathrm{and} \mathrm{Willis} {\mathrm{F}}_{\mathrm{MAX}}=\left(1+\frac{P}{D}\right)$$

(3)

F—gradient of fracturing pressure (psi/ft)

P—gradient pore pressure (psi/ft)

D—length (ft)

$$\mathrm{Matthews} \mathrm{and} \mathrm{Kelly} \mathrm{F}=\frac{Ki\mu }{D}+\frac{P}{D}$$

(4)

Ki—coefficient of tension die

µ—vertical of tension die (psi)

D—length (ft)

$$\mathrm{Ben} \mathrm{Eaton} \mathrm{F}=\frac{\left(S-P\right)}{D}\ast \frac{\yen }{1-\yen }+\frac{P}{D}$$

(5)

S—tension of formation rocks (psi)

¥—Poisson coefficient

D—length (ft)

3. Results and Discussion

Figure 4 shows our area of interest where a well with a depth of 2735 m was drilled. From a geological point of view, this is an area where hydrostatic deposit pressures are assumed, where the exploration focuses on sandstone formations with the expected occurrence of natural gas with condensate. After drilling and cementing 9^5/8″ casing at 1081 m, a LOT was performed and we decided to perform a FIT. This test was chosen due to the presence of hard plastic grey-black clays, which confirmed the samples taken from the bottom hole during drilling and decided a position of casing shoe.

Figure 5 shows a seismic measurement, where we can see the compactness of the upper layers to 1600 m depth. Deeper layers are the initializing elements of the deposit trap also in the form of faults, where hydrocarbons could accumulate.

The next part is deciding whether to use the FIT or LOT procedure. These procedures must be subject to API laws, API RP 59 [21].

The following procedure was proposed:

Procedures of FIT or LOT

• Perform casing integrity test;
• Prepare a Leak-off test form;
• Drill out a casing shoe and drill 5 m of new hole;
• Circulate bottom up to condition mud and stabilize a mud density;
• Pull up into casing. Make sure that not pump a slug or LCM prior to the test;
• Rig up pumping unit, pump mud through test lines, and make a surface lines pressure tests;
• Close annular or pipe rams of BOP;
• Pump down the drill pipe at 40 or 80 L/min. Maintain the constant pump rate assigned;
• During the test, record and plot cumulative volume pumped vs. drill pipe pressure for every 40 L/m pumped, regardless of the pump rate;
• Permeability in the open hole may cause pressure build-up to be non-linear. If this occurs, stop the test, bleed pressure to zero, and retest at a pump rate that is 40 to 80 L/min higher than the previous test;
• Continue pumping until the predetermined maximum pressure is reached or until leak-off is confirmed;
  • If pressure decreases, stop the pump immediately. Check surface lines and valves for leaks and make test again;
  • If pressure levels off far below required pressure or leak-off, pump additional volume and check if a pressure increase;
  • If performing a FIT test do not exceed maximum pressure required;
• When leak-off is confirmed, or maximum pressure is reached, stop pumping and close the shut-in valve;
• Observe and record shut-in pressure vs. time. Check surface lines and valves for leaks. If it is ok, continue, if not, perform a retest;
• Release pressure and record volume of fluid come back.

After performing the FIT procedure, we obtained the values shown in Figure 6. The pressure exerted against the rock was 68 bar and its equivalent to the maximum mud weight is 1.74 kg/L. Converting mud weight to the depth of the borehole, we obtained the equivalents of the maximum pressures. Figure 7 shows recalculated values of equivalent pressures against the mud weight. Another important step before continuing drilling to the final depth was to perform and recalculate the slow pump rates, which helps us in case of a gas kick.

Values of lithology, such as pressures, temperatures, depth of formations, etc., were determined from the surrounding wells. In

Table 1. Measured data from A-1 well.

Name	Depth (MD)	Depth (TVD)	Overpressure (%)	Pressure (MPa)	Pressure (Psi)	SG eqv.	Temperature (°C)
Holocene-Pleistocene	0	0	0				10
Top Upper Pannionan	970	954.6	0	9.36	1357	1.00	65
Top Újfalu	1202	1185	0	11.62	1684	1.00	77
Dynamo ULN 33 top	1522	1505	0	14.76	2141	1.00	93
Dynamo ULN 33 base	1552	1535	0	15.06	2183	1.00	95
Dynamo-Deep ULN 33 top	1572	1555	0	15.25	2212	1.00	96
Dynamo-Deep ULN 33 base	1602	1585	0	15.55	2254	1.00	97
Top Algyö	1671	1600	0	15.75	2276	1.00	98
Top Miocene	2227	2210	15	24.93	3615	1.15	130
TD	2316	2299	15	25.94	3760	1.15	135

can be seen the pressure values that the pressures in the formations do not differ significantly up to 1600 m. For this reason, we have assessed that the FIT values will be sufficient for the procedure. The well was designed that the final depth will be 2745 m deep. Hydrostatic pressures are expected in the well. Another option was also considered in the project, in the event that pressures are higher than the hydrostatic pressure in the well, occurring at greater depths.

Continuing the drilling, we reached a depth of 2721 m, where we noticed the inflow of the medium into the well. It was evaluated as a gas kick. The well was shut in and we followed the gas kick procedures. We read and recorded the pressures SIDP and SICP. The drilling mud used at this depth had a density of 1.33 kg/L, and this equivalent is 44 bar Figure 7.

Due to the large thickness open horizon in the formation, we must pay attention to the quick shut -in in the well during a gas kick in the well, preventing a subsequent big influx into the well. After the shut-in in the well, the pressure on the SICP increased from 12 to 44 bar. This was the critical MAASP value for the fluid density, where cracking of the casing shoe and loss of fluid, or the destruction of the entire well, could occur. In Figure 8 we can see the point where the gas kick was detected.

In the Figure 9 is a visible increase a pressure (red line) compared to the equivalent calculations of the current density (drilling mud) (blue line) of drilling mud. At the point where the straight lines intersect, it can be seen that the pressure has exceeded the MAASP. In this situation, cracks can form, so, for this reason, we used the FIT rather than the LOT procedure, which gave us a kind of safety factor (reserve).

In this case, we have the opportunity to use one of the drilling methods. We know several possible procedures:

• The first option:

  -

  Use the drilling method to reduce the pressure on the bottom hole pressure and circulate the gas out. Assuming that the pressure will be constant, continue with the drilling method [22].

• The second option:

  -

  If the pressure is still increasing, use the Weight and Wait method and while a crew prepared a killing mud, we will release the pressure on the casing and hold a constant pressure on the SIDP [22].

• The third option:

  -

  Apply bullheading method [22].

• The fourth option:

We can try to use a concurrent method which is a combination of Driller, and Weight and Wait method.

We start the pumps by gradually increasing the strokes to the value killing liters, with a current constant pressure of casings (using a hydraulic choke). Once we reach the ICP value, we start to increase mud weight and pump. Gradual loading is directly proportional to the adjustment of the circulation pressure. We continue circulation until it returns to the surface at same density and then the well is killed. We turn off the pumps again and make a flow check.

With each of the options, the most important thing is the correct calculation of the values in the kill sheet, the ICP and FCP values.

In Figure 10 is a suggested algorithm to simplify working steps while decision making—yes–no–maybe. If the value of LOT and FIT is so low (approx. 30 bar), when calculating the MAASP, the maximum increasing the density of the drilling mud is up to 1.32 kg/L, which can be very difficult in the event of larger gas kick.

The Driller’s method is best able to handle the pressure effect against the deposit and against the fracture pressure in the casing shoe.

In case of increasing pressure during the pressure rise, the pump strokes are reduced. In the case of large pressure with a low value fracturing pressure we suggest the wait and weight method, where time is essential, because the amount of influx that enters could seriously fracking at casing shoe. For this reason, during the preparation of kill fluid we are going to gradually release the pressure on the annulus to avoid of casing shoe.

After preparing the fluid, we will make bigger depression in front of the deposit, but only with one circulation circuit. This is how we circulate gas out from the well.

With each of the options, the most important thing is the correct calculation of the values in the kill sheet, the ICP and FCP values. To achieve better filtration and rheological properties, it is advisable to create an optimal drilling fluid (e.g., use of a polymer temperature stabilizer) [23,24].

4. Conclusions

LOT or FIT help us by properly designing a casing shoe during deep drilling. That means MAASP calculations will provide us with a larger interval of the safety factor, which is necessary and important in these activities.

In this article, a theoretical example was shown where the system of casings was correctly designed, and based on this, we obtained ideal values of the fracture pressures.

Based on the data obtained from practice, we recalculated the values of the fracture pressures and obtained the data that are necessary to safely handle pressure events without cracking the formation.

We propose an algorithm to simplify work procedures during well control to minimize formation pressures against deposit and casing shoe.

From the calculation, it is clear that the Drillers method is the most suitable method for well control and formation pressure in casing shoe. Using this example, we pointed out how the beginning of the gas kick affects the surrounding rocks, in the event that the pressure values approach the limit of fracking pressures. We pointed out the possibilities of correct procedures that should be performed in the correct sequence to avoid rock cracking and destruction of the well and related problems. The methodology of the correctness of procedures in drilling processes has been perfected by years of practice. It is necessary to emphasize and point out fact that each case is specific and, therefore, we approach the problem individually.

The novelty of the article is the discovery and subsequent use of a suitable method (e.g., Drillers, W/W, Concurent) of well control during a gas kick.