Drilling Technology

Purposes of Oil Well Cementing

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Primary Casing Job. Casing strings are usually cemented in the hole 1) to isolate troublesome zones behind the casing from deeper formations to be drilled, 2) to isolate high pressure formations below the casing from the weaker, shallow zones behind the casing, and 3) to isolate producing zones from waterbearing sands. In some wells, the primary cement job serves several purposes (Figs. 9-1 to 9-3).

The cement is normally placed behind the casing in a single- or multistage technique. The single-stage technique pumps cement down the easing and up the annulus. The heavier cement in the annulus is prevented from U-tubing by back-pressure valves in the bottom of the casing string.

Various drilling conditions may warrant that several sections of the annulus be cemented without cementing the entire annulus. A common cause is the g

Casing

Open hole

Lost circulation 2one

Cement

Heaving

Heaving

Casing

Fig. 9-1 isolation of troublesome zones behind the casing from deeper formations to be drilled

Fig. 9-2 Isolation of higher pressure formations below the casing from the weaker, shallower zones behind the casing

	/ Î
s s s ■>	A	^Cement *
	C		£	* ; Water sand
	f s
	f <		s «1
	î		s	; : oil sand : ; : :

1. 9-3 Isolate producing zones from water-bearing sands
2. 9-3 Isolate producing zones from water-bearing sands presence of a lost circulation zone that negates the possibility of circulating cement up to the desired height. Another cause may be hole sections that require the use of different types of cement slurries (Fig. 9-4)i

The initial stage of a multistage job is usually planned as if it were a single-stage effort. Cement is pumped down the casing (or stabbed-in drilipipe) and up the annulus. The next stage is pumped through a special port collar at the desired location up the annulus. The port is opened after the initial stage is cemented.

Fig. 9-4 Example of multistage cementing due to lost circulation zone

Liners are cemented in a slightly different fashion than casing strings. Since liners are run into the well on the bottom of the drillstring, the cement slurry must be pumped through the pipe prior to entering the liner. After the slurry has circulated down the liner and up the liner annulus, the excess slurry volume is pumped from the well to reduce drilling-out problems and time requirements.

Circulating the excess volume after a liner job has caused problems in some wells. As a result, preplanning is important. If the volume of cement is circulated up the annulus, additional time will be required, which may result in cement hardening in the annulus. If the volume is reversed-out of the well through the drillpipe, the friction and hydrostatic pressures acting on the casing seat may cause lost circulation (see Example 9.1), Many industry personnel believe the high frequency of squeeze jobs required for liner overlaps may be a result of the reversing-out technique. Calculations can be performed to determine the best circulation route.

Example 9.1

A liner is planned for a well. A 30-bbl cement excess volume will be used. The cement will be pumped at 5 bbl/min, which generates 1,000 and 200 psi friction pressure in the drillstring and annulus, respectively, above the liner top. The mud and cement densities are 14.4 and 16.4 lb/gal, respectively.

Determine if lost circulation will occur at any of the following conditions: tions:

1, The 30-bbl excess volume is above the liner top in a static condition.

2, The 30-bbl excess volume is pumped out of the hole via the annulus, i.e., the "long way."

3, The 30-bbl excess volume is pumped out of the hole via the drillpipe, i.e., reversed-out or the "short way."

Fracture gradient at 10,000 ft Solution:

Drillpipe Capacity Liner top Liner depth Casing seat Annulus capacity

9,400 ft, 47rin. OD 0,01422 bbl/ft 9,400 ft 12,000 ft 10,000 0.05 bbl/ft 16.8 lb/gal

1. Convert the fracture gradient to pressure:
2. 052 X J6.8 lb/gal x 10,000 ft = 8,736 psi
3. The 30-bbl excess volume will have the following vertical heights:

amiU,US: 0.05 bbl/ft = 600 ft drillpipe: " 2,109 ft

3. The pressure on the casing seat when the 30-bbl excess volume is above the liner top in a static condition with 600-ft cement-filled overlap is as follows:

[ (600 ft) + (10,000 - 9,400) ] (0.052 x 16.4 lb/gal) - 1,023 psi 0,052 X 14.4 lb/gal X 8,800 ft - 6,589 psi

Total = 7,612 psi

Since 7,612 psi < 8,736 psi, lost circulation will not occur. 4. Pumping the cemcnt out of the annulus will not change the hydrostatic pressures from step 3. However, it will add a circulating pressure of 200 psi:

7,612 psi + 200 psi < 8,736 psi

1. , the lost circulation will not occur at this point if the "long way" is used,
2. Reversing-out will add 1,000 psi initially to the annulus hydrostatic pressure:

Lost circulation will not occur when reversing-out is started.

6. The hydrostatic pressure inside the drillpipe with the 30 bbl of cement is:

	2,109 ft	X	0.052	X	16.4 lb/gal =	1,798 psi
(9,400 -	2,109 ft)	X	0,052	X	14.4 lb/gal =	5,459 psi
(10,000 -	9,400 ft)	X	0.052	X	16.4 lb/gal =	511 psi (annulus to

_ easing seat)

Total = 7,768 psi

_ easing seat)

Total = 7,768 psi

Since 7,768 psi < 8,736 psi, lost circulation will not occur when the drillpipe contains the 30-bbl excess volume in a static pressure. This pressure (7,768) is increased by 1,000 psi, however, when pumping occurs.

Therefore, circulation could be lost at this time.

Squeeze Cementing. A common method for repairing faulty primary casing jobs or performing remedial operations on the hole is squeeze cementing. Major applications for squeeze cementing are as follows:

<• supplement a faulty primary casing cement job

• reduce water-oil, water-gas, or gas-oil ratio
• abandon a productive zone temporarily
• isolate a zone before perforation for production (block squeezes) or before fracturing
• repair casing leaks
• stop lost circulation in an open hole while drilling
• bring a well under control

Placement techniques and slurry design are important considerations in squeeze operations.

Supplementing a faulty or ineffective primary casing cement job is the most prominent application for squeeze cementing. The initial cement job may have failed to hold pressure under integrity tests, or cement bond logs may have indicated poor or absent cement bonding, (See Chapter 17 for details on cement bond logs.) Since the primary job is a major well control system (see Figs. 9-1 to 9-3), a bad job must be augmented with additional cement. Generally, this additional cement must be forced, or "squeezed," around the annulus by using high pump pressures. Squeeze techniques are discussed later in this chapter.

The reduction of producing fluid ratios by squeeze cementing is a common, necessary practice on many wells. High gas volumes may deplete reservoir pressure prematurely, while high water volumes may create excessive separation costs at the surface production facilities or retard production. Specific sections of perforations may be closed by pumping cement. Gas volumes are reduced by cementing the upper perforations, while water is reduced by cementing the lower perforations (Fig. 9-5),

Lost circulation problems can often, but not always, be solved by squeeze cementing. The type of lost circulation must respond to cement. For example, cementing a zone fractured from excessive pressures will not solve the problem unless the pressures are reduced.

Plugs. Setting plugs in the well commonly is used for the following reasons:

• plugback
• whipstock
• abandonment

Fig. 9-5 Squeeze cementing can be used to control gas-oil ratios

A balanced plug technique is used usually for the placement technique.

A plug-back operation may set a plug through or above the old pay zone when recompletion above a depleted producing zone is necessary, A plug may also be used in open-hole completions to shut off bottom-hole water.

A whipstock is often used when it becomes necessary to increase or decrease the deviation of a hole or to change direction while drilling. The whipstock tool requires a solid cement plug to provide a seat or bridge. Whipstocks are also used to bypass junk or to reach a new objective.

Good operating practices and the rules of regulatory bodies require abandoning wells in such a manner that fluid-bearing zones are properly sealed and protected. Cement plugs are commonly used to seal and protect these zones (Fig. 9-6). As many as three plugs are set in deep wells. A plug is usually set at the bottom of the surface casing or deeper casing string. Uncased freshwater sands in abandoned wells are protected by plugs extending from below to above the sands. Government regulations with jurisdiction over the wellsite should be consulted for specific abandonment procedures.

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