Testing of Drilling Systems

drill mudTo properly control the hole cleaning, suspension, and filtration properties of a drilling fluid, testing of the fluid properties is done on a daily basis. Most tests are conducted at the rig site, and procedures are set forth in the API RPB13B. Testing of water-based fluids and nonaqueous fluids can be similar, but variations of procedures occur due to the nature of the fluid being tested.

Water-Base Muds Testing
To accurately determine the physical properties of water-based drilling fluids, examination of the fluid is required in a field laboratory setting. In many cases, this consists of a few simple tests conducted by the derrickman or mud Engineer at the rigsite. The procedures for conducting all routine drilling fluid testing can be found in the American Petroleum Institute’s API RPB13B.

Density Often referred to as themudweight, densitymaybe expressed as pounds per gallon (lb/gal), pounds per cubic foot (lb/ft3), specific gravity (SG) or pressure gradient (psi/ft). Any instrument of sufficient accuracy within ±0.1 lb/gal or ±0.5 lb/ft3 may be used. The mud balance is the instrument most commonly used. The weight of a mud cup attached to one end of the beam is balanced on the other end by a fixed counterweight and a rider free to move along a graduated scale. The density of the fluid is a direct reading from the scales located on both sides of the mud balance .
Marsh Funnel Viscosity
Drilling Mud testMud viscosity is a measure of the mud’s resistance to flow. The primary function of drilling fluid viscosity is a to transport cuttings to the surface and suspend weighing materials. Viscosity must be high enough that the weighting material will remain suspended but low enough to permit sand and cuttings to settle out and entrained gas to escape at the surface. Excessive viscosity can create high pump pressure, which magnifies the swab or surge effect during tripping operations. The control of equivalent circulating density (ECD) is always a prime concern when managing the viscosity of a drilling fluid. The Marsh funnel is a rig site instrument used to measure funnel viscosity. The funnel is dimensioned so that by following standard procedures, the outflow time of 1 qt (946 ml) of freshwater at a temperature of 70±5◦F is 26±0.5 seconds. A graduated cup is used as a receiver.

Direct Indicating Viscometer
This is a rotational type instrument powered by an electric motor or by a hand crank . Mud is contained in the annular space between two cylinders. The outer cylinder or rotor sleeve is driven at a constant rotational velocity; its rotation in the mud produces a torque on the inner cylinder or bob. A torsion spring restrains the movement of the bob. A dial attached to the bob indicates its displacement on a direct reading scale. Instrument constraints have been adjusted so that plastic viscosity, apparent viscosity, and yield point are obtained by using readings from rotor sleeve speeds of 300 and 600 rpm.
Plastic viscosity (PV) in centipoise is equal to the 600 rpm dial reading minus the 300 rpm dial reading. Yield point (YP), in pounds per 100 ft2, is equal to the 300-rpm dial reading minus the plastic viscosity. Apparent viscosity in centipoise is equal to the 600-rpm reading, divided by two.

Gel Strength
Gel strength is a measure of the inter-particle forces and indicates the gelling thatwill occur when circulation is stopped. This property prevents the cuttings from setting in the hole. High pump pressure is generally required to “break” circulation in a high-gel mud. Gel strength is measured in units of lbf/100 ft2. This reading is obtained by noting the maximum dial deflection when the rotational viscometer is turned at a low rotor speed (3 rpm) after the mud has remained static for some period of time (10 seconds, 10 minutes, or 30 minutes). If the mud is allowed
to remain static in the viscometer for a period of 10 seconds, the maximum dial deflection obtained when the viscometer is turned on is reported as the initial gel on the API mud report form. If the mud is allowed to remain static for 10 minutes, the maximumdial deflection is reported as the 10-min gel. The same device is used to determine gel strength that is used to determine the plastic viscosity and yield point, the Variable Speed

API Filtration
A standard API filter press is used to determine the filter cake building characteristics and filtration of a drilling fluid
The API filter press consists of a cylindrical mud chamber made of materials resistant to strongly alkaline solutions. A filter paper is placed on the bottom of the chamber just above a suitable support. The total filtration area is 7.1
(±0.1) in.2. Below the support is a drain tube for discharging the filtrate into a graduated cylinder. The entire assembly is supported by a stand so 100-psi pressure can be applied to the mud sample in the chamber. At the end of the 30-minute filtration time, the volume of filtrate is reported as API filtration in milliliters. To obtain correlative results, one thickness of the proper 9-cm filter paper—Whatman No. 50, S&S No. 5765, or the equivalent—must be
used. Thickness of the filter cake is measured and reported in 32nd of an inch. The cake is visually examined, and its consistency is reported using such notations as “hard,” “soft,” tough,” ’‘rubbery,” or “firm.”

Sand Content
The sand content in drilling fluids is determined using a 200-mesh sand sieve screen 2 inches in diameter, a funnel to fit the screen, and a glass-sand graduated measuring tube . The measuring tube is marked to indicate the volume of “mud to be added,” water to be added and to directly read the volume of sand on the bottom of the tube.
Sand content of the mud is reported in percent by volume. Also reported is thepoint of sampling (e.g., flowline, shale shaker, suctionpit). Solids other than sand may be retained on the screen (e.g., lost circulation material), and
the presence of such solids should be noted.

Liquids and Solids Content
A mud retort is used to determine the liquids and solids content of a drilling fluid. Mud is placed in a steel container and heated at high temperature until the liquid components have been distilled off and vaporized. The vapors are passed through a condenser and collected in a graduated cylinder. The volume of liquids
(water and oil) is then measured. Solids, both suspended and dissolved, are determined by volume as a difference between the mud in container and the distillate in graduated cylinder. Drilling fluid retorts are generally
designed to distill 10-, 20-, or 50-ml sample volumes.

For freshwater muds, a rough measure of the relative amounts of barite and clay in the solids can be made (Table 1.1). Because both suspended and dissolved solids are retained in the retort for muds containing substantial
quantities of salt, corrections must be made for the salt. Relative amounts of high- and low-gravity solids contained in drilling fluids can be found in Table 1.1.

Two methods for measuring the pH of drilling fluid are commonly used: (1) a modified colorimetric method using pH paper or strips and (2) the electrometric method using a glass electrode . The paper strip test may not be reliable if the salt concentration of the sample is high.
The electrometric method is subject to error in solutions containing high concentrations of sodium ions unless a special glass electrode is used or unless suitable correction factors are applied if an ordinary electrode is used. In addition, a temperature correction is required for the electrometric method of measuring pH.
The paper strips used in the colorimetric method are impregnated with dyes so that the color of the test paper depends on the pH of the medium in which the paper is placed. A standard color chart is supplied for comparison
with the test strip. Test papers are available in a wide range, which permits estimating pH to 0.5 units, and in narrow range papers, with which the pH can be estimated to 0.2 units.
The glass electrode pH meter consists of a glass electrode, an electronic amplifier, and a meter calibrated in pH units. The electrode is composed of (1) the glass electrode, a thin-walled bulb made of special glass within
which is sealed a suitable electrolyte and an electrode, and (2) the reference electrode, which is a saturated calomel cell. Electrical connection with the mud is established through a saturated solution of potassium chloride
contained in a tube surrounding the calomel cell. The electrical potential generated in the glass electrode system by the hydrogen ions in the drilling mud is amplified and operates the calibrated pH meter.

Control of the resistivity of the mud and mud filtrate while drilling may be desirable to permit enhanced evaluation of the formation characteristics from electric logs. The determination of resistivity is essentially the measurement of the resistance to electrical current flow through a known sample configuration. Measured resistance is converted to resistivity by use of a cell constant. The cell constant is fixed by the configuration of the sample in the cell and id determined by calibration with standard solutions of known resistivity. The resistivity is expressed in ohm-meters.

Filtrate Chemical Analysis
Standard chemical analyses have been developed for determining the concentration of various ions present in the mud. Tests for the concentration of chloride, hydroxyl, and calcium ions are required to fill out the API drilling mud report. The tests are based on filtration (i.e., reaction of a known volume of mud filtrate sample with a standard solution of known volume and concentration). The end of chemical reaction is usually indicated by the change of color. The concentration of the ion being tested can be determined from a knowledge of the chemical reaction taking place.

The chloride concentration is determined by titration with silver nitrate solution. This causes the chloride to be removed from the solution as AgCl−, a white precipitate. The endpoint of the titration is detected using a potassium chromate indicator. The excess Ag present after all Cl− has been removed fromsolution reactswith the chromate to formAg9CrO4, an orange-red precipitate. Contamination with chlorides generally results from drilling salt or from a saltwater flow. Salt can enter and contaminate themudsystem when salt formations are drilled and when saline formation water enters the wellbore.

Alkalinity and Lime Content
Alkalinity is the ability of a solution or mixture to react with an acid. The phenolphthalein alkalinity refers to the
amount of acid required to reduce the pH of the filtrate to 8.3, the phenolphthalein end point. The phenolphthalein alkalinity of the mud and mud filtrate is called the Pm and Pf , respectively. The Pf test includes the effect of only dissolved bases and salts, whereas the Pm test includes the effect of both dissolved and suspended bases and salts. The m and f indicate if the test was conducted on the whole mud or mud filtrate. The Mf alkalinity refers to the amount of acid required to reduce the pH to 4.3, the methyl orange end point. The methyl orange alkalinity of the mud and mud filtrate is called the Mm and Mf , respectively. The API diagnostic tests include the determination of Pm, Pf , and Mf . All values are reported in cubic centimeters of 0.02N (normality= 0.02) sulfuric acid per cubic centimeter of sample. The lime content of the mud is calculated by subtracting the Pf from the Pm and dividing the result by 4.
The Pf and Mf tests are designed to establish the concentration of hydroxyl, bicarbonate, and carbonate ions in the aqueous phase of the mud. At a pH of 8.3, the conversion of hydroxides to water and carbonates to bicarbonates
is essentially complete. The bicarbonates originally present in solution do not enter the reactions. As the pH is further reduced to 4.3, the acid reacts with the bicarbonate ions to form carbon dioxide and water.
ml N/50H2SO4 to reach pH=8.3
CO 3(-2) +H2SO4→HCO3(-) +HSO4
OH−+H2SO4→HOH+SO4=  hydroxyl+acid→water+sulfate salt
The Pf and Pm test results indicate the reserve alkalinity of the suspended solids. As the [OH−] in solution is reduced, the lime and limestone suspended in the mud will go into solution and tend to stabilize the pH
(Table 1.2). This reserve alkalinity generally is expressed as an excess lime concentration, in lb/bbl of mud. The accurate testing of Pf, Mf , and Pm are needed to determine the quality and quantity of alkaline material present
in the drilling fluid. The chart below shows how to determine the hydroxyl, carbonate, and bicarbonate ion concentrations based on these titrations.

Total Hardness
The total combined concentration of calcium and magnesium in the mud-water phase is defined as total hardness. These contaminants are often present in the water available for use in the drilling fluid makeup. In addition, calcium can enter the mud when anhydrite (CaSO4) or gypsum (CaSO4 ·2H2O) formations are drilled. Cement also contains
calcium and can contaminate the mud. The total hardness is determined by titration with a standard (0.02 N) versenate hardness titrating solution (EDTA). The standard versenate solution contains sodium versenate, an
organic compound capable of forming a chelate when combined with Ca2 and Mg2.
The hardness test sometimes is performed on the whole mud as well as the mud filtrate. The mud hardness indicates the amount of calcium suspended in the mud and the amount of calcium in solution. This test usually is made on gypsum-treated muds to indicate the amount of excess CaSO4 present in suspension. To perform the hardness test on mud, a small sample of mud is first diluted to 50 times its original volume with distilled water so that any undissolved calcium or magnesium compounds can go into solution. The mixture then is filtered through hardened filter paper to obtain a clear filtrate. The total hardness of this filtrate then is obtained using the same procedure used for the filtrate from the low-temperature, low-pressure API filter press apparatus.

Methylene Blue Capacity (CEC or MBT)
It is desirable to know the cation exchange capacity (CEC) of the drilling fluid. To some extent, this value can be correlated to the bentonite content of the mud. The test is only qualitative because organic material and other clays present in the mud also absorb methylene blue dye. The mud sample is treated with hydrogen peroxide to oxidize most of the organic material. The cation exchange capacity is reported in milliequivalent weights (mEq) of methylene blue dye per 100 ml of mud. The methylene blue solution used for titration is usually 0.01 N, so that the cation exchange capacity is numerically equal to the cubic centimeters of methylene blue solution per cubic centimeter of sample required to reach an end point. If other adsorptive materials are not present in significant quantities, the montmorillonite content of the mud in pounds per barrel is calculated to be five times the cation exchange capacity.
The methylene blue test can also be used to determine cation exchange capacity of clays and shales. In the test, a weighed amount of clay is dispersed into water by a high-speed stirrer ormixer. Titration is carried out as
for drilling muds, except that hydrogen peroxide is not added. The cation exchange capacity of clays is expressed as milliequivalents of methylene blue per 100 g of clay.

Oil Well Planning

Drilling optimization requires detailed engineering in all aspects of well planning, drilling implementation, and post-run evaluation Effective well planning optimizes the boundaries, constraints, learning, nonproductive time, and limits and uses new technologies as well as tried and true methods. Use of decision support packages, which document the reasoning behind the decision-making, is key to shared learning and continuous improvement processes. It is critical to anticipate potential difficulties, to understand their consequences, and to be prepared with
contingency plans. Post-run evaluation is required to capture learning.
Drilling Planning

Many of the processes used are the same as used during the well planning phase, but are conducted using new data from the recent drilling events. Depending on the phase of planning and whether you are the operator
or a service provider, some constraints will be out of your control to alter or influence (e.g., casing point selection, casing sizes, mud weights, mud types, directional plan, drilling approach such as BHA types or new technology
use). There is significant value inbeing able to identify alternate possibilities for improvement over current methods, but well planning must consider future availability of products and services for possible well interventions.
When presented properly to the groups affected by the change, it is possible to learn why it is not feasible or to alter the plan to cause improvement. Engineers must understand and identify the correct applications for technologies to reduce costs and increase effectiveness.Acorrect application understands the tradeoffs of risk versus rewardandcosts versus benefits.

Boundaries Boundaries are related to the “rules of the game” established by the company or companies involved. Boundaries are criteria established by management as “required outcomes or processes” and may relate to
behaviors, costs, time, safety, and production targets.
Constraints Constraints during drilling may be preplanned trip points for logs, cores, casing, and BHA or bit changes. Equipment, information, human resource knowledge, skills and availability, mud changeover, and dropping balls for downhole tools are examples of constraints on the plan and its implementation.
The Learning Curve Optimization’s progress can be tracked using learning curves that chart the performance measures deemed most effective for the situation and then applying this knowledge to subsequent wells.
Learning curves provide a graphic approach to displaying the outcomes. Incremental learning produces an exponential curve slope. Step changes may be caused by radically new approaches or unexpected trouble. With
understanding and planning, the step change will more likely be in a positive direction, imparting huge savings for this and future wells. The curve slope defines the optimization rate. The learning curve can be used to demonstrate the overall big picture or a small component that affects the overall outcome. In either case, the curve measures the rate of change of the parameter you choose, typically the “performance measures” established by you and your team. Each performance measure is typically plotted against time, perhaps the chronological order of wells drilled as shown in figure below:

Cost Estimating Oneof the mostcommonand critical requests of drilling engineers is to provide accurate cost estimates, or authority for expenditures (AFEs). The key is to use a systematic and repeatable approach that takes
into account all aspects of the client’s objectives. These objectives must be clearly defined throughout the organization before beginning the optimization and estimating process. Accurate estimating is essential to maximizing a company’s resources. Overestimating a project’s cost can tie up capital that could be used elsewhere, and underestimating can create budget shortfalls affecting overall economics.
Integrated Software Packages With the complexity of today’s wells, it is advantageous to use integrated software packages to help design all aspects of the well. Examples of these programs include

• Casing design
• Torque and drag
• Directional planning
• Hydraulics
• Cementing
• Well control
Decision Support Packages Decision support packages document the reasoning behind the decisions that are made, allowing other people to understand the basis for the decisions. When future well requirements change, a decision trail is available that easily identifies when new choices may be needed and beneficial.
Performance Measures Common drilling optimization performance measures are cost per foot of hole drilled, cost per foot per casing interval, trouble time, trouble cost, and AFEs versus actual costs.
Systems Approach Drilling requires the use of many separate pieces of equipment, but they must function as one system. The borehole should be included in the system thinking. The benefit is time reduction, safety improvement, and production increases as the result of less nonproductive time and faster drilling. For example, when an expected average rate of penetration (ROP) and a maximum instantaneous ROP have been identified, it is possible to ensure that the tools and borehole will be able to support that as a plan. Bit capabilities must be matched to the rpm, life, and formation. Downhole motors must provide the desired rpm and power at the flow rate being programmed. Pumps must be able to provide the flow rate and pressure as planned.
Nonproductive Time Preventing trouble events is paramount to achieving cost control and is arguably the most important key to drilling a cost-effective, safe well. Troubles are “flat line” time, a terminology emanating from the days versus depth curve when zero depth is being accomplished for a period of days, creating a horizontal line on the graph. Primary problems invariably cause more serious associated problems. For example, surge pressures can cause lost circulation, which is the most common cause of blowouts. Excessive mud weight can cause differential sticking, stuck pipe, loss of hole, and sidetracking. Wellbore instability can cause catastrophic loss of entire hole sections. Key seating and pipe washouts can cause stuck pipe and a fishing job.
When a trouble event leads to a fishing job, “fishing economics” should be performed. This can help eliminate emotional decisions that lead to overspending. Several factors should be taken into account when determining
whether to continue fishing or whether to start in the first place.
The most important of these are replacement or lost-in-hole cost of tools and equipment, historical success rates (if known), and spread rate cost of daily operations. These can be used to determine a risk-weighted value of
fishing versus the option to sidetrack.
Operational inefficiencies are situations for which better planning and implementation could have saved timeandmoney. Sayings such as“makin’ hole” and “turnin’ to the right” are heard regularly in the drilling business.
These phases relate the concept of maximizing progress. Inefficiencies which hinder progress include
• Poor communications
• No contingency plans and “waiting on orders” (WOO)
• Trips
• Tool failure
• Improper WOB and rpm (magnitude and consistency)
• Mud properties that may unnecessarily reduce ROP (spurt loss, water loss and drilled solids)
• Surface pump capacities, pressure and rate (suboptimum liner selection and too small pumps, pipe, drill collars)
• Poor matching of BHA components (hydraulics, life, rpm, and data acquisition rates)
• Survey time
Limits Each well to be drilled must have a plan. The plan is a baseline expectation for performance (e.g., rotating hours, number of trips, tangibles cost). The baseline can be taken from the learning curves of the best experience that characterizes the well to be drilled. The baseline may be a widely varying estimate for an exploration well or a highly refined measure in a developed field. Optimization requires identifying and improving on the limits that play the largest role in reducing progress for the well being planned. Common limits include
1. Hole Size. Hole size in the range of 7 7/8 – 8 1/2 in. is commonly agreed to be the most efficient and cost-effective hole size to drill, considering numerous criteria, including hole cleaning, rock volume drilled, downhole tool life, bit life, cuttings handling, and drill string handling. Actual hole sizes drilled are typically determined by the size of production tubing required, the required number of casing points, contingency strings, and standard casing decision trees. Company standardization programs for casing, tubing, and bits may limit available choices.
2. Bit Life. Measures of bit life vary depending on bit type and application. Roller cones in soft to medium-soft rock often use KREVs (i.e., total revolutions, stated in thousands of revolutions). This measure fails to consider the effect ofWOBon bearing wear, but soft formations typically use medium to high rpm and low WOB; therefore, this measure has become most common. Roller cones in medium to hard rock often use a multiplication of WOB and total revolutions, referred to as the WR or WN number, depending on bit vender. Roller cone bits smaller than 7 7/8 in. suffer significant reduction in bearing life, tooth life, tooth size, and ROP. PDC bits, impregnated bits, natural diamond bits, and TSP bits typically measure in terms if bit hours and KREVs. Life of all bits is severely reduced by vibration. Erosion can wear bit teeth or the bit face that holds the cutters, effectively reducing bit life.
3. Hole Cleaning. Annular velocity (AV) rules of thumb have been used to suggest hole-cleaning capacity, but each of several factors, including mud properties, rock properties, hole angle, and drill string rotation, must be considered. Directional drilling with steerable systems require “sliding” (not rotating) the drill string during the orienting stage; hole cleaning can suffer drastically at hole angles greater than 50. Hole cleaning in large-diameter holes, even if vertical, is difficult merely because of the fast drilling formations and commonly low AV.
4. Rock Properties. It is fundamental to understand formation type, hardness, and characteristics as they relate to drilling and production. From a drilling perspective, breaking down and transporting rock (i.e., hole cleaning) is required. Drilling mechanics must be matched to the rock mechanics. Bit companies can be supplied with electric logs and associated data so that drill bit types and operating parameters can be recommended that will match the rock mechanics. Facilitating maximum production capacity is given a higher priority through the production zones. This means drilling gage holes,minimizing formation damage (e.g., clean mud, less exposure time), and facilitating effective cement jobs.
5. Weight on Bit. WOB must be sufficient to overcome the rock strength, but excessive WOB reduces life through increased bit cutting structure and bearing wear rate (for roller cone bits). WOB can be expressed in terms of weight per inch of bit diameter. The actual range used depends on the “family” of bit selected and, to some extent, the rpm used. Families are defined as natural diamond, PDC, TSP (thermally stable polycrystalline), impregnated, mill tooth, and insert.
6. Revolutions per Minute (rpm). Certain ranges of rpm have proved to be prudent for bits, tools, drill strings, and the borehole. Faster rpm normally increases ROP, but life of the product or downhole assembly may be severely reduced if rpm is arbitrarily increased too high. A too-low rpm can yield slower than effective ROP and may provide insufficient hole cleaning and hole pack off, especially in high-angle wells.
7. Equivalent Circulating Density (ECD). ECDs become critical when drilling in a soft formation environment where the fracture gradient is not much larger than the pore pressure. Controlling ROP, reducing pumping flow rate, drill pipe OD, and connection OD may all be considered or needed to safely drill the interval.
8. Hydraulic System. The rig equipment (e.g., pumps, liners, engines or motors, drill string, BHA) may be a given. In this case, optimizing the drilling plan based on its available capabilities will be required.
However, if you can demonstrate or predict an improved outcome that would justify any incremental costs, then you will have accomplished additional optimization. The pumps cannot provide their rated horsepower
if the engines providing power to the pumps possess inadequate mechanical horsepower. Engines must be down rated for efficiency.
Changing pump liners is a simple cost-effective way to optimize the hydraulic system. Optimization involves several products and services and the personnel representatives.This increases the difficulty to achieve an optimized parameter selection that is best as a system.

New Technologies

Positive step changes reflected in the learning curve are often the result of effective implementation of new technologies:
1. Underbalanced Drilling. UBD is implemented predominantly to maximize the production capacity variable of the well’s optimization by minimizing formation damage during the drilling process. Operationally, the pressure of the borehole fluid column is reduced to less than the pressure in the ZOI. ROP is also substantially increased. Often,
coiled tubing is used to reduce the tripping and connection time and mitigate safety issues of “snubbing” joints of pipe.
2. Surface Stack Blowout Preventer (BOP). The use of a surface stack BOP configurations in floating drilling is performed by suspending the BOP stack above the waterline and using high-pressure risers (typically 13 3/8 in. casing) as a conduit to the sea floor. This method, generally used in benign and moderate environments, has saved considerable time and money in water depths to 6,000 ft.
3. Expandable Drilling Liners. EDLs can be used for several situations. The casing plan may startwith a smaller diameter than usual, while finishing in the production zone as a large, or larger, final casing diameter. Future advances may allow setting numerous casing strings in succession, all of the exact same internal diameter. The potential as a step change technology for optimizing drilling costs and mitigating risks is phenomenal.
4. Rig Instrumentation. The efficient and effective application of weight to the bit and the control of downhole vibration play a key role in drilling efficiency. Excessive WOB applied can cause axial vibration, causing destructive torsional vibrations. Casing handling systems and top drives are effective tools.
5. Real-Time Drilling Parameter Optimization. Downhole and surface vibration detection equipment allows for immediatemitigation. Knowing actual downhole WOB can provide the necessary information to perform improved drill-off tests .
6. Bit Selection Processes. Most bit venders are able to use the electric log data (Sonic,GammaRay, Resistivity as aminimum)and associated offset information to improve the selection of bit cutting structures. Formation
type, hardness, and characteristics are evaluated and matched to the application needs as an optimization process.

Well Pressure Control

Basically all formations penetrated during drilling are porous and permeable to some degree.
Fluids contained in pore spaces are under pressure that is overbalanced by the drilling fluid pressure in the well bore.
The borehole pressure is equal to the hydrostatic pressure plus the friction pressure loss in the annulus. If for some reason the borehole pressure falls below the formation fluid pressure, the formation fluids can enter the well. Such an event is known as a kick. This name is associated with a rather sudden flowrate increase observed at the surface.

A formation gas or fluid kick can be efficiently and safely controlled if the proper equipment is installed at the surface. One of several possible arrangement of pressure control equipment . The blowout preventer (BOP) stack consists of a spherical preventer (i.e.,Hydril) and ram type BOPs with blind rams in one and pipe rams in another with
a drilling spool placed in the stack.
A spherical preventer contains a packing element that seals the space around the outside of the drill pipe. This preventer is not designed to shut off the well when the drill pipe is out of the hole. The spherical preventer allows stripping operations and some limited pipe rotation.

Hydril Corporation, Shaffer, and other manufactures provide several models with differing packing element designs for specific types of service. The ram type preventer uses two concentric halves to close and seal around the pipe, called pipe rams or blind rams, which seal against the opposing half when there is no pipe in the hole. Some pipe rams will only seal on a single size pipe; 5 in. pipe rams only seal around 5 in. drill pipe. There are also variable bore rams, which cover a specific size range such as 312 in. to 5 in. that seal on any size pipe in their range.
Care must be taken before closing the blind rams. If pipe is in the hole and the blind rams are closed, the pipe may be damaged or cut. A special type of blind rams that will sever the pipe are called shear blind rams.
These rams will seal against themselves when there is no pipe in the hole, or, in the case of pipe in the hole, the rams will first shear the pipe and then
continue to close until they seal the well. A drilling spool is the element of the BOP stack to which choke and kill lines are attached. The pressure rating of the drilling spool and its side outlets should be consistent with BOP stack. The kill line allows pumping mud into the annulus of the well in the case that is required. The choke
line side is connected to a manifold to enable circulation of drilling and formation fluids out of the hole in a controlled manner.
A degasser is installed on the mud return line to remove any small amounts of entrained gas in the returning drilling fluids. Samples of gas
are analyzed using the gas chromatograph.
If for some reason the well cannot be shut in, and thus prevents implementation of regular kick killing procedure, a diverter type stack is used rather, the BOP stack described above. The diverter stack is furnished with a blow-down line to allow the well to vent wellbore gas or fluids a safe distance away from the rig.

While drilling, there are certain warning signals that, if properly analyzed, can lead to early detection of gas or formation fluid entry into the wellbore.
1. Drilling break. A relatively sudden increase in the drilling rate is called a drilling break. The drilling break may occur due to a decrease in the difference between borehole pressure and formation pressure. When a drilling break is observed, the pumps should be stopped and the well watched for flow at the mud line. If the well does not flow, it probably means that the overbalance is not lost or simply that a softer formation has be encountered.
2. Decrease in pump pressure. When less dense formation fluid enters the borehole, the hydrostatic head in the annulus is decreased. Although reduction in pump pressure may be caused by several other factors, drilling personnel should consider a formation fluid influx into the wellbore as one possible cause. The pumps should be stopped and the return flow mud line watched carefully.
3. Increase in pit level. This is a definite signal of formation fluid invasion into the wellbore. The well must be shut in as soon as possible.
4. Gas-cut mud. When drilling through gas-bearing formations, small quantities of gas occur in the cuttings. As these cuttings are circulated up, the annulus, the gas expands. The resulting reduction in mud weight is observed at surface.
Stopping the pumps and observing the mud return line help determine whether the overbalance is lost.
If the kick is gained while tripping, the only warning signal we have is an increase in fluid volume at the surface (pit gain). Once it is determined that the pressure overbalance is lost, the well must be closed as quickly as possible. The sequence of operations in closing a well is as follows:
1. Shut off the mud pumps.
2. Raise the Kelly above the BOP stack.
3. Open the choke line
4. Close the spherical preventer.
5. Close the choke slowly.
6. Record the pit level increase.
7. Record the stabilized pressure on the drill pipe (Stand Pipe) and annulus pressure gauges.
8. Notify the company personnel.
9. Prepare the kill procedure.
If the well kicks while tripping, the sequence of necessary steps can be given below:

  1. Close the safety valve (Kelly cock) on the drill pipe.
    2. Pick up and install the Kelly or top drive.
    3. Open the safety valve (Kelly cock).
    4. Open the choke line.
    5. Close the annular (spherical) preventer.
    6. Record the pit gain along with the shut in drill pipe pressure (SIDPP) and shut in casing pressure (SICP).
    7. Notify the company personnel.
    8. Prepare the kill procedure.
    Depending on the type of drilling rig and company policy, this sequence of operations may be changed.

A formation fluid influx (a kick) may result from one of the following
• abnormally high formation pressure is encountered
• lost circulation mud weight too low
• swabbing in during tripping operations
• not filling up the hole while pulling out the drill string
• recirculating gas or oil cut mud.
If a kick is not controlled properly, a blowout will occur.
A blowout may develop for one or more of the following causes:
• lack of analysis of data obtained from offset wells
• lack or misunderstanding of data during drilling
• malfunction or even lack of adequate well control equipment

1. Drilling Equipment and Operation.
2. drilling Operation.