WorldOil's Cementing oil and gas wells . . . including
casing handling procedures
BY GEORGE o. SUMAN, JR. .AND RICHARD C. ELLIS
Acknowledgment This handbook is the result of a comprehensive study of cementing oil and gas wells including casing handling procedures. The authors' basic work was sponsored by AMF Tubescope, Inc.; Bakerline, a division of Baker International Corp.; Dowell Schlumberger; Oil Tool Division, PENGO Industries, Inc.; Lynes, Inc.; Texas Iron Works, Inc., and Varco International, Inc. The authors wish to express their appreciation to these companies for their sponsorship and for the complete freedom allowed in preparation of all material. Thanks are also due the sponsors and many other manufacturers for providing information and illustrations, and to those in industry who reviewed the manuscript and contributed many helpful suggestions.
All
WOl'ld Oil
P.O. Box 2608
Copyright@ 1977 rights reserved
Houston, Texas 77001
Tableof Contents
CementingOil and Gas Wells Handbook Part 1-Basic functions of cement are given, with concepts to consider in mud, pipe and hole preparation to prevent job failure . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 5 Part 2-Casing inspection and pipe handling methods, including thread make-up control, hydrostatic testing, landing practices . . . . . . . . . . . . . . . . . . . . . . .14 Part 3-How basic cements and additives can be tailored to give desired properties for completion and remedial operations. . . .22 Part 4-Practical interpretation of rheology, annular displacing forces. How to avoid bypassing mud during primary cementing .32 Part 5-Guidelines for downhole equipment use, stage cementing methods, new concepts for cementing large diameter casing . . . . . . . . . . . . . . . . . . .41 Part 6-Liner applications and equipment used for installation. Common problems to avoid while pumping, displacing cement 50 Part 7-A review of cement plug placement, tubingless completion techniques and the art and science of cement squeezing Part 8-Methods for evaluating primary cementing effectiveness plus a wrapup of several new tools to improve completion operations
57
66
About the authors GEORGEO. SUMAN, JR., attended the California Institute of Technology and the University of California (Berkeley), graduating with a B.SM.E. in 1952. He spent two years with Aramco in Saudi Arabia and 18 years with Shell Oil Co. working primarily with drilling, completion and stimulation design and application. In 1978 he formed Completion Technology Co. which is actively working with a number of client companies in improving well reliability and profitability. Mr. Suman has authored many technical papers on well completion and drilling techniques and he holds numerous patents and applications in these specialties. He is a member of API and SPE and a registered professional engineer in Louisiana and Texas. RICHARDC. ELLIS graduated from the Wisconsin Institute of Technology in 1962 with a B.S.M.E. and from the University of Wisconsin in 1968 with the M.S. in mining engineering. He spent nine years with Shell Oil Co. working on design and application of artificial lift, sand control and well completions for primary, waterflood and thermal recovery operations, both onshore and offshore. His latest assignment with Shell was production engineering section leader for the Western U.S. and Alaska. Mr. Ellis joined the staff of Completion Technology Co. in 1976. He is a member of SPE and a registered professional engineer in Texas.
Cementing oil and gas wells ... includingcasinghandlingprocedures Part 1-Basic functions of cement are given, with concepts to consider in mud, pipe and hole preparation to prevent job failure George o. Suman, Jr., President and Richard C. Ellis, Project Engineer, CompletionTechnologyCo., Houston 10-second summary Opening article discusses basic cement properties in relation to ability to support casing loads and prevent damage or joint loss. Mud selection, and procedures to prevent differential pipe sticking during cementing are given, and examples of casing defects found in new pipe are shown to encourage careful pre-job pipe handling.
About the series Field engineers and others who handle casing and cementing for present-day wells are responsible for one of the most critical phases of well completion. It has never been so important from the standpoint of safety, environmental protection and economics to insist that the best-available technology be applied. Unfortunately, much important research and technical development has not been interpreted and applied directly to the operational phase in a straightforward and concise manner. It is the objective of the authors of this exclusive new series to fill that large gap between research and field operations. The following subjects will be covered in the eight articles: 1. Functions of cement, precautions to take during drilling, common causes of casing and connection failures 2. Casing handling, recommendations for inspection, make-up and testing 3. Cement slurry chemistry and use of additives 4. Displacement mechanics and rheology considerations, need for pipe movement and centralization
FROM THE COMPLETIONSPECIALIST'Sviewpoint, proper primary cementing should be the operator's main concern. Poor displacement efficiency which leaves a substantial volume of mud at the cement-formation interface can lead to just about every completion and production problem in the book-oil and gas can be lost from the pay zone, stimulation fluids and enhanced recovery chemicals can bypass the formation, extraneous fluids may be produced and the borehole may not be properly supported. It is important to plan for the primary cement job long before casing is run into the hole, to avoid common problems such as improperly conditioned mud and stuck pipe. And the casing string itself should be carefully inspected and handled to avoid damage that can cause failure in otherwise properly designed strings. This article introduces critical concepts to consider in preparing for the primary cement job, including discussions of: ~ The function of the cement sheath in supporting the formation and protecting the casing from various WORLD OIL
1977
5. Primary cementing, proper use of downhole and surface equipment 6. Liner cementing, techniques, problems, evaluate results 7. Special cementing, recent innovations, squeezes, plug-backs, tubingless completions
how to remedial
8. Job evaluation methods, logging, how to locate tops and define bond effectiveness, tests for zonal separation. A format similar to WORLDOIL'S Sand Control Series (November 1974-June 1975) will be followed in these presentations, including sequential development and discussion of concepts and application, with frequent reference to preceding material. The authors make liberal use of published literature with grateful acknowledgment of the original investigators. An extensive reference list is included, and to get maximum benefit from this series, readers are encouraged to pursue the original works where important concepts cannot be adequately discussed due to space limitations. -Editor
5
FORCE
CEMENT SLURRY
U
~}--
;':' ::: f;~i;
A
'"
'_..
n.....
SHEAR BOND PRESSURE
B
::,:';: PRESSURE
>':;~: ':':\~ .
;\..=~. "~',::j:
.'
HYDRAULIC
BOND
'.'.. ".' .';. ,.:..: .-" 0-'
0
.. .... ,.. . . .. '\': '.',.
.;
:";
"
;i~
m ".. ':j
I
.
.
." ~~'; .
~:.
.
'.
I
CEMENT
/
1f7 ~U'..
.
'C
SAWED-OFF HERE FOR BOND TEST
Fig. 1-Lab tests to measure casing/cement bonding characteristics. Test A3 measures axial loading strength. Test B3, C' and D' measure hydraulic bond. In test C, after cementing under controlled pressure, the casing is sawed off 10 check bonding. Test D, is a direct measure of cement/pipe adhesion strength in samples formed in a 7-inch mold.
kinds of damage such as fault shear, perforating tion, and joint loss while drilling ~ Drilling fluid selection and conditioning cement displacement efficiency and prevent pipe sticking during cementing, and
to improye differential
Discussions are illustrated by schematic drawings, curves, tabular data and photographs. An extensive reference list appears at the end of the article. Cement used in primary cementing is normally designed:
1. To support the axial load of the casing string and strings to be run later 2. To seal intended production or injection intervals from overlying or underlying permeable sections (zone isolation) 3. To protect the casing from damage or failure, and the productive
AXIAL LOAD SUPPORT High axial loads may be imposed on the casing string and/or surrounding cement by landing and suspension methods and later operations. And the cement strength 6
Based on these worst-case results, Bearden and Lane2 provided a relationship for determining support capability of a cement sheath, conservatively utilizing results for mud-wetted and non-displaced co ndi tions. ModHying their relationship to utilize compressive strength (assumed to be 10 times tensile strength), gives the formula: F=O.969
ScdH,
Where: F Sc d H
deforma-
~ Common causes of casing failure that can adversely affect the cement job as well as future operations, including mill defects appearing in new pipe.
4. To support the borehole through interval.
required to support such axial casing loads has been determined through shear bond testS.1,2.3 The axial load which breaks the cement bond has been measured with the test apparatus shown in Fig. 1(A) . In this test where the surface in question is the outer periphery of the inside pipe, the ability of cement to support axial casing loads was found to be proportional to the area of contact between cement and the casing. Therefore, support coefficient,2 shear bond3 or sliding resistance,4 as it is described by various investigators, is the load required to break the bond, divided by the surface area between cement and pipe. Shear bond strength increases with cement tensile or compressive strength as shown in Fig. 2.2 A fairly narrow range of shear bond at a given tensile strength resulted for various cement compostions tested. And a significant reduction in shear bond was caused by mud wetting of the pipe. Poorest results were obtained when the pipe was mud-wetted and no attempt was made to remove the mud film.
= = = =
force or load to break cement bond, pounds compressive strength, psi outside diameter of casing, inches height of cement column, feet.
For example: using
For one bonded
500 psi compressive
500 X 7 X 1 =
strength
foot of 7-inch casing, cement: F 0.969 X
=
3,390 pounds.
Required strength. The load to break the cement bond during hanging and drilling-out operations normally would not exceed weight of the casing string (such as surface pipe) plus miscellaneous loads (such as weight on bit when drilling out the shoe joint). Therefore, the load capacity noted above, 3,390 pounds per foot of cement column, provided by the relatively low compressive strength of 500 psi, should be more than adequate to handle anticipated axial loads. Thus, as this example indicates, the equation permits calculation of approximate load capacity for various pipe sizes and cement compressive strengths. Cement compositions normally can be formulated to rapidly develop adequate strength for casing landing loads. This allows drilling operations to proceed with little or no waiting-on-cement (WOC) time. Also, low strength "filler" cements, which are relatively inexpensive and of low density-and less likely to induce lost circulation when high cement columns are requiredmay have adequate compressive strength to meet axial load support requirements. In addition to water-based mud wetting of the pipewhich is allowed for in the above equation-other factors WORLD OIL
1977
that affect cement shear bond performance to axial load are:
with respect 350
. Casing collars, which increase the ability of the cement to support axial loads
'. Low water-to-cement ratios which increase slurry density and improve shear bond because of increased compressive strength, Fig. 3.4 . Radial loads imposed on cement and casing by the formation, which should increase shear bond due to the increased friction between pipe and cement
300\
~ 250,
ci
on the exterior
of the casing which
ffi
50
o o 50 100 150 200 250 300 CEMENTTENSILESTRENGTH,PSI
mud is not removed
such as increase coating because
. Raw cement characteristics, such as fineness of grind, may also affect shear bond strength . Cement contamination by mud which lowers shear bond appreciably, see Fig. 3. . Displacement mechanics and efficiency which affect thickness and continuity of the cement sheath around the casing, and . Pressure/temperature effects which can contract the casing diameter after the cement hardens. This factor will be discussed in a later article.
ZONE ISOLATION Although cement with a low compressive strength may be adequate to handle axial and rotational casing loads, high ultimate strength may be required for zone isolation and to support the borehole. Therefore, cement compositions should be selected which quickly provide adequate compressive strength for continued drilling operations but which also provide adequate strength, ultimately, for production operations. A comprehensive study of factors governing zone isolation under downhole conditions would be very complex. Zone isolation depends, in part, on load interactions between formation, cement and casing, some of which are not well understood. Further difficulty arises in determining type and magnitude of loads imposed by fluid injection pressures and temperatures, and production pressure drawdown and depletion. For these reasons, only qualitative judgements have been attempted in studies to date and these usually relate to the "hydraulic bond" which indicates adhesion between casing and cement, or between cement and formation. The actual relationship between hydraulic bond measured in the lab, and downhole zone isolation has not been reported, if such a determination has been made. Bonding test. Various investigators3,5,6 have measured hydraulic bond. Test arrangements are shown in Fig. 1(B) .3,6 and Fig. 1(C) 5 Pressure is applied to the exterior surface of the casing causing the casing to become 1977
Fig. 2-Effect of cement tensile strength and mud wetting on shear bond. Most cements fall in narrow range except
where
. Roughness of the exterior casing surface, rust or special resin-sand coatings, which can shear bond substantially6 (Normally such special would not be required for axial load support minimum shear bond strength is adequate)
WORLD OIL
:
is 200 , m a: 150
. Oil-based mud wetting of the pipe which lowers shear bond to a greater extent than water-based mud wetting . Mill varnish lowers shear bond
TYPE CEMENT 1. (C) 2. SPECIAL (A) 3. (A) 6% GEL 4. (A) 5. (A) LATEX 6. OXYCHLORIDE CEMENT 7. (A) MUD WET, WATER WASHED 8. EMULSION CEMENT 9. 50/50 POZ., 2% GEL 10. (A) DISPLACED PAST MUD WET PIPE 11. (A) MUD WET, NO DISPLACEMENT
(after
Bearden
and
-FRESH ---SALT -'-RED ~-OIL .,~.:.~
CI Z 0'
WATER MUD WATER MUD MUD EMULSION MUD
-
,,,............ .. ~.... "....................... ..
"
m
~I wt
J:; en
0=, 0.2
Lane)'.
'", . ..
5 10 15 VOLUME MUD, %
0.4 0.6 0.8 WATER/CEMENTRATIO
20
Fig. 3-Water content and mud contamination lower shear bond strength. Absolute value of shear bond is not shown but the scale is linear so that percent change can be estimated (after Becker and Petersen)'. smaller in diameter and "pull away" from the cement, forming a micro-annulus which permits leakage. Hydraulic bond strength in the test shown in Fig. 1(B) ranges from 100 to 1,200 psi for water and from 45 to 450+ psi for gas (nitrogen) depending on roughness of the exterior pipe surface and type of mud wetting, see below. No fixed correlation between cement compressive strength and hydraulic bond was found.
Hydraulic bond YS. casing surface and type of fluid wetting3,6 Type mud wetting
Surface finish
-
Hydraulic bond (psi) Water
Gas
None None Varnishremoved(chemical).. . . None Varnishremoved(sand-blasl).... Fresh water Varnishremoved(sand-blast)... . Varnishremoved(sand-blast).... Invert oil emulsion Oilbase Varnishremoved (sand-blast)....
200-250 300-400 500-700 100 100 100
150 50 50 50
None Resin-sandcoat (new,sand blast) Fresh water Resin-sandcoat (new, sand blat) Resin-sandcoat (new, sand biast) Invert oil emulsion Oilbase Resin-sandcoat (new,sand blast)
1,100-1,200 100 100 ICO
450 55 45 45
New mill-varnished.""
, '" "
.
Cement: API Class A Water Content: 5.2 galjsk Curing temperature: 80°F Curing time: 24 hours Casing size: 2" inside 4"
Hydraulic bond strength is improved by resin-sand coatings, as shown above, only when there is no mud wetting. Such coatings consist of graded sand bonded by 7
Effect of mud film on bond strength 6000
Surfacecondition BEFORE
4'12" CASING
Dry
PERFORATING
Mudfilm......... Dry .... Mudfilm .... Dry . Mudfilm .... Dry . Mudfilm .... Dry . Mudfilm.........
.4000
Ci5 11.
:i" 2000 le!) Z W a: Io CJ) W >
i
fl .:.
Ci5
I!:\:
.
:::E
8 4000 _
PE~FORATION
PRESSURE
2%" TUBING
2000
o
o
2000
4000
6000
Fig. 4- Test setup to measure perforating effects on hydraulic bond with pressure from inside and outside. Targets were tested, then perforated In a separate pressurized well, then returned for testing as shown. Perforations were placed about two inches from the bottom of the 12-lnch targets. Results are plotted in curves. Lower curve shows bond was usually destroyed when compressive strength was below about 2,000 psi (after Godfrey and Methven)13.
epoxy to the exterior of the pipe by the patented RuffCote process. These coatings normally are rated to 3003250 F. The pressure at which failure of the hydraulic bond occured in the test shown in Fig. 1(C) can be increased by: 1. Preventing formation of the micro-annulus by controlling pressure differential across the casing as the cement sets, and/or 2. Attaching seal rings of deformaJble rubber to the exterior of the casing (sealing rings designed to stop migration of fluid between the casing surface and the inside of the cement sheath are available for field installation. And the above tests indicate such devices should increase zonal separation efficiency) . However, zone isolation is routinely obtained in the field at greater differential pressures than those causing failure in these hydraulic bond tests. Therefore, such tests are probably not completely representative of downhole conditions everywhere. Effects of mud wetting. Further tests were conducted to more directly measure adhesion between cement and pipe,7 Fig. 1(D). These tests, do show an advantage for the resin-sand exterior, in the mud-wetted condition, which was not apparent in the previously discussed test, see table. However, it should be emphasized that when resin-sand coatings are used downhole, effectiveness should be increased by removing mud from the casing surface using pre-flushes ahead of the cement and cement scouring.
8
Surface coating Mill varnish Millvarnish Rusty Rusty Acid etched Acid etched Sandblasted Sandblasted Epoxy coated, 6-12 mesh sand Epoxy coated, 6-12 mesh sand
Hydraulic bond, psi <20 <20 350-450 20-50 250-400 40-50 500-600 50-60 700-950 500-600
Curing time: 24 hours Curing temperature: 120 F
HOLLOW CARRIER JET o EXPENDABLE JET .
6000
CJ) w a: 11.
.
And
casing using the Ruff-Cote process should be well
centralized to avoid imbedding mudcake or shale into the roughened surface. Preventing such imbedment might not be possible in irregular, doglegged or high angle hole, or where mud is poorly conditioned. One important advantage of the resin-sand treatment would be that formation of a micro-annulus under certain pressure/temperature conditions might be prevented. This result appears to be verified by cement-bond logs.8 Cement-formation bond. Still other tests have been conducted to examine the bond between cement and formation. In one lab investigation3 in which cement was placed into contact with formation cores and the interface was tapped by a simulated perforation, the effect of various contact surfaces (dry, mud layer) and applied squeeze pressure was evaluated. Bond strength was found to depend on degree of contact between cement and formation. When a mud cake was present between cement and formation, bond strength was greatly reduced for all cases examined. When cement was squeezed against dry cores, bond strength approached or exceeded formation compressive strength. Test results were not provided for low compressive and/ or low tensile strength formation materials such as unconsolidated sands and some shales. Presumably, little or no bond strength would be indicated for these materialsyet zone isolation is obtained in the field. Although these results may be indicative of various relationships, tests more closely simulating downhole conditions might provide further insight into the requirements for zone isolation. Cement vs. perforating damage. Operators have generally considered cement with 2,000 psi or less compressive strength optimum for perforating-a belief based on appearance of targets perforated with bullets and/or jets at the surface, under simulated downhole conditions.9.lo Visual inspection of such perforated targets containing higher strength cement revealed cracks in the sheath. Application of results of these tests is wrong because: Atmospheric tests of explosives are more damaging than those performed under pressure due to greater expansion of detonation gases, and cement with hairline fractures may still prevent fluid leakage. Godfrey11 measured shear and hydraulic bond strengths on samples before and after perforating with single hollow carrier and expandable jet charges, under simulated downhole pressure conditions (3,000 or 5,000 psi). The test arrangement, Fig. 4, prevented creation of a microannulus and the cement was loaded in compression from outer and inner surfaces, as well as from the bottom. The 1-9/16-inch OD hollow carrier gun used a 3.2 gram WORLD OIL
1977
chaxge and the expendable 1-11/16-inch OD charge was 10.0 grams. Before perforating, hydraulic bond strength increased with increased compressive strength, Fig. 4. Hydraulic bond strength was destroyed by perforating when cement compressive strength was low, Fig. 4, but was unaffected when cement compressive strength exceeded 2,000 psi. Therefore, high compressive strength cement appears best from the standpoint of zone isolation. Expandable guns vs. carrier guns. The cemen t sheath tends to minimize casing damage caused hy expendable perforating charges,12.l3 Fig. 5. And expendable guns of nominal charge, for example through-tubing guns, may be used with little or no danger of serious casing damage. Although damage may occur to flawed or mill defective casing, particularly if unsupported by cement. However, expendable charges may split casing collars that are unsupported by cement.13 And large expendable guns, over about 20 grams, frequently damage partially supported or unsupported casing. Conventional hollow carrier, steel shaped-charge guns cause only slight casing deformation and essentially no damage regardless of support, because most of the forces from the exploding charges are contained by the carrier body. However, no data has yet been reported on the effect of using extra strength charges in carrier guns, or special chaxges designed to produce larger than normal holes. As another important point, it was also determined in perforating tests12 that cement compressive strength is not an important factor in preventing casing deformation at the perforation point, Fig. 5. CASING
SUPPORT
PROTECTION
The cement sheath between casing and borehole serves an important function in protecting the pipe from the stresses of formation movement, and in preventing unscrewing and possible loss of bottom joints in surface and intermediate strings. However, certain properties of this cement such as its contriobutions to collapse resistance of the installed casing may be greatly overrated. Salt flow. Casing damage can be caused by lateral loads resulting from flow of salt formations.14 Salt may flow in various ways depending on combinations of overburden load and temperature. And it may not be economically practical to design casing for the most severe situations of non-uniform loading which can occur, such as the "flattening" effect illustrated in Fig. 6 (top). However, when the annulus is completely filled with cement, casing is subjected to a nearly uniform loading approximately equal to the overburden pressure, and, although modes of failure may be different, casing design, to withstand uniform salt pressure can be computed on the same basis as designs to withstand fluid pressure. Failure of casing by non-uniform loading in inadequately cemented washed-out salt sections should be considered a drilling and cementing problem rather than a casing design problem. Salt-saturated or oil-based drilling fluids axe often used during drilling to minimize washouts, and in special cases salt-saturated cement is used during cementing. Fault shear. WORLD OIL
Casing failure caused by formation 1977
move-
w 0.5 :I: o ~ 0.4 z C/)
g
0.3
a:
~ w
0.2
~ en
0.1
o
Z o
o
o
0.3
~
10 20 30 STRENGTH FACTOR x 10' (WALL THICK x YIELD)
40
r--
~ffi0.2 0:1: LLO ~ 0.1 (!) z
~
en t3
o
1 2 3 4 5 6 7 CEMENTCOMPRESSIVESTRENGTHx 1,000, PSI
Fig. 5-Cement support minimizes casing deformation caused by expendable perforating guns as shown by curves, top, from tests with 20 gram charges, at 1,000 psi and 1800 F conditions. The three cases represent no cement, a :lA-inch sheath held by thin steel and a strongly encased sheath. Compressive strength of the sheath was less important, as indicated by second curve, bottom (after Bell and Shore)."
ment along natural or induced fault planes-as opposed to salt flow-is best handled by elimination of cement through the affected interval and perhaps opening the hole to enable fault slippage to take place without loading the casing in shear/s,lG Fig. 6 (bottom). Other downhole conditions, such as borehole doglegs and sand control failure,17 also may cause casing damage similar to the types described above. The type of load condition may be deduced through geology, petrophysics, and operational correlations and measurements of the damage configuration.18 Tools are available for establishing the cross-section (collapse) and deflection (buckling or shear) of moderately damaged pipe. Knowledge of failure mechanism is essential to selection of the failure prevention method, i.e. cement sheath or no cement sheath. Casing joint loss. Adequate cement strength and good cementing and operational practices may be required to prevent parting or other failure in the bottom joints of surface and intermediate casing strings.19 In most cases, failure in the bottom few joints of casing is not discovered until electric logs show that the bottom one, two, or three joints have parted from the string and slipped down the hole. In other cases, the parted section uncovers a high pressure or lost circulation zone, or it shifts laterally, restricting passage of drilling equipment. Analysis of possible causes of such failure19 indicate that the casing is unscrewed rather than broken. The unscrewing occurs because of short-lived, high-level torque impulses transmitted to the casing by the bit as it hangs up while drilling cement and cementing equipment out of the bottom joints. The problem is normally prevented by welding or using thread locking compounds on the 9
in directionally
2. Weld threads on H-40 pipe with a ~-inch fillet weld (see cautions below) or properly clean threads on J-55or higher grades with volatile (not oily) solvent, and apply thread~locking compounds to both sides of the lowermost couplings, including the three to six couplings joining the bottom four to seven joints. When a bottom plug is used, Schuh19 recommends strengthening three couplings; when a plug is not used, six couplings.
LOADING
3. Follow other good practices to be discussed in this series, i.e. proper downhole casing equipment, pipe movement, high displacement rates, chemical washes or spacers ahead of cement, adequate centralization, etc.
SALT FLOW
~
MUD ONLY
Fig. 6-Cement sheath effects with formation loading. Strong, well centralized cement sheath, top, can prevent flattening effect of salt flows in washed out holes (Cheatham and McEver)". But In fault slippage zones, bottom, cement sheath may cause more damage by holding pipe rigid through shear zone.
TOP PLUG
CEMENT SLURRY MUD FILM CASING
-- -
----
- - ---
~MUD
CEMENT SLURRY
I MUDACCUMULATION FROMFILM
Fig. 7-Mud film on casing should be removed by bottom plug when displacing. Drawing shows how, with top plug only, mud is removed after slurry passes to build up under the plug and be deposited in the critical area around the shoe joint (after Owsley)'.. connections below.
and
controlling
rotary
speed,
as discussed
To avoid loss of joints when cement is to be drilled out of the shoe, these practices should be followed:
1. Select a competent formation for the casing point. Drill-out with drilling fluid which will maintain stability of this formation. Avoid dogleg sections, or sharp curves 10
4. Use good quality cement that will develop high early compressive strength, and adequate shear bond, for the last portion of the slurry to fill the annulus-from shoe upwards 200. to 400 feet (or 10.% of casing length) . Elevate compressive and shear bond strength of the cement around lower joints by decreasing water-to-cement ratio (increasing density) of last portion of slurry, Fig. 3. 5. Use two plugs. Without a bottom plug, mud film from the inside casing wall can accumulate beneath the top plug and be deposited in and around the shoe joints/a Fig. 7. Fill-up for various film thicknesses can be significant, for example: For 10,000 feet of 5~-inch casing, 1/16, 1/32 and 1/64-inch thick films would fill 510, 260. and 130 feet, respectively. Even when a top plug is used, accurate displacement calculations should be made to avoid over-displacement and mud or water contamination around the shoe.
FAULT SLIPPAGE
1--'
drilled holes near the casing point.
6. Release surface pressure following cement placement to minimize chance for a micro-annulus to form between casing and cement. However, surface pressure is sometimes used as an aspect of casing landing operation to prevent casing instability and buckling conditions.21 7. Do not disturb casing until cement has obtained initial set-about three times thickening time. Keep drill pipe out of the hole until after this time. The cement composition should have minimum 500 psi compressive strength (some say 1,000 psi) at time of drilling-out.
8. Control rotary speed while drilling cement out of casing, as indicated in Fig. 8. But if the casing joints have been improperly strengthened, i.e. misapplied thread locking compound or welded J-55 or higher grade casing, permissible rotary of values shown.
speed may be only one-tenth
or less
Welding recommendations. Lower casing grades, H-40, present few problems. However, field personnel should be a ware that higher grades can be downgraded and sold as lower grades, i.e. up to 80,000 psi yield strength pipe can be downgraded to H-40. Thus grades should be positively identified before welding. Also, casing collars and other downhole casing equipment are sometimes manufactured of higher grade steel. Welding on high grade tubulars is critical, requiring careful preheating and use of special electrodes (P-IIO, and C-75 should never be welded). Here are a few important points to remember when welding oil field tubulars: 22 Use only low hydrogen electrodes. Always preheat N-80; preheating is preferable on J-55; H-40 can be WORLD OIL
1977
welded without preheat. Preheating temperature should be 500-600° F and it should not drop below 4000 F during welding. The weld should cool at ambient temperatures. A Tempilstik type crayon should be used to verify and carefully control temperatures. Collapse support questionable. A lowered casing design safety factor in collapse (perhaps 0.85 versus 1.125) is sometimes considered for casing to be used below the cement top, on the assumption that cement will provide additional support.23 Such a practice is not valid. According to Cheatham and McEver/4 cement in the annulus between salt and casing is compressed by salt pressure, reducing stress transmitted to the casing. However, this reduction is calculated to be less than 5% for 8-5/8-inch casing cemented in 12-inch hole, or about 200 psi for a pressure of 6,000 psi acting on the cement. Further, this load reduction depends on uniform placement of cement in the annulus-a condition which is not normally achieved throughout the column. Other tests24 suggest that a cement sheath may provide greater collapse resistance support for lower casing grades (H-40, J-55). However, minor radial or longitudinal discontinuities in the cement sheath eliminate this support. Therefore, the cement sheath should have no bearing on the decision to use a low collapse safety factor.
500
.@
~ :E300 Cl)CL >a: a:.
<5
b0200 a:..... w:::!
~~ 150 Cl)Cj
:Ez =>a;
~ ;;1100
~~ :E
90 80" 70 60 4
5
5'12 6 6'12 7 7'12 8 DRILL COLLAR SIZE, INCHES
9
10
Fig. 8-Maximum safe rotary speed for drilling out cement and cementing equipment for all grades of casing strengthened with thread-locking compound, and for H-40 grade casing strengthened with a full-circumference weld (after Schuh)'". Note: If joints are not properly strengthened, safe speeds can be one-tenth those shown.
PRECAUTIONS DURING DRILLING Favorable conditions for primary cementing should be established long before the actual cementing operation. It is particularly important to select hole and casing sizes, and drilling fluid properties, which maximize mud displacement efficiency and minimize likelihood for differential pressure sticking and swab/surge pressures. Drilling fluids should be selected and drilling operations conducted-so as to minimize borehole washouts. For instance, the ideal drilling fluid: 1. Is non-thixotropic (little or no gel strength) with low plastic viscosity and yield point, to maximize displacement efficiency and minimize swab-surge pressures. 2. Has low weight with low solids content and low filtration loss with a thin cake to minimize likelihood of differential pressure sticking, and 3. Is compatible
with
cement
composition.
Such conditions cannot always be attained in actual practice. For instance, in deep, hot wells it is difficult to maintain low gel strength, yield point and plastic viscosity-particularly with weighted muds. These conditions, combined with long trip time and casing running time, lead to mud properties that can be most unfavor3lble by the time the job is initiated. However, when effective cementing is important, and it is feasible to maintain low density fluids, an effort should be made to achieve the conditions noted above. Other factors influencing favorable mud displacement and swab/surge pressures will be discussed in a later article. The differential pressure sticking concept25. 26.27 is very important to understand, and this problem must be prevented if casing movement (reciprocation and/or rotation) is planned during cementing operations. Otherwise the casing may become stuck after being run to WORLD OIL
1977
Fig. 9-Differential sticking of casing occurs in a permeable zone when pipe contacts mud cake as shown, left, then filtrate loss causes cake thining, right, which increases contact area, (1) to (2), in turn increasing force holding pipe to wall (after Outmans)".
bottom and before completion of cementing, and movement during that most critical period28 may not be possible. Differential pressure exists across a mud cake, with pressure on the inside consisting of mud column weight plus pressure increase due to annular flow. External pressure is the pore pressure of the surrounding permeable formation. This differential pressure causes water in the mud to continuously flow through the filter cake into the formations. While the casing is in motion, contact with the filter cake is lubricated by a thin layer of drilling mud, which continues to supply filtrate. When pipe movement is interrupted or stopped, the casing seals off the cake from the filtrate supply in the contact area and the cake begins to thin as water continues to be driven into the surrounding permeability, see Fig. 9. As the cake thins, the contact area increases, the pipe is pressed against the wall with greater force, and the contacted surface changes from mud to solid clay particles. This pressure loading effect and the high friction factor between pipe and cake solids can increase hook load until the casing cannot be moved.
How to prevent sticking. During cementing, differential 11
. Sticking generally occurs after an interruption of pipe movement or long interruption disturbances of wall cake
of circulation,
or
. Circulation, if interrupted, can be restarted after the casing becomes stuck. This helps identify sticking, as opposed to wall caving, which would likely prevent circulation . A small clearance between casing and borehole is conducive to /Wall sticking because it tends to increase casing/film cake contact area. This contact area can be reduced by using centralizers and/or designing the well to have a larger borehole.
A
. High deviation of the borehole also tends to increase contact area, and . High weight, high water loss and high-solids-content fluids can increase the friction factor between casing and filter cake. Muds are available which provide cakes with lower coefficients of friction.29 CASING
c
B
Fig. 10-Defects
rolled into the pipe wall at the mill. Photo A shows pits left by mill slugs that penetrate 0.210 inch into a 0.337-inch wall. Photo B shows the hole left by a broken-out metal fold (lamination) that was rolled into the wall but did not fuse. Photo C is another example of pitting caused by removal of foreign material rolled into the outer surface. ,"*
;~,->c."'*.ra;,.:~~~>"""""..
FAILURE CAUSES
Obtaining an effective casing/cement installation requires proper inspection, care and handling, and make-up of the casing itself. Without such treatment, even properly designed casing may fail. Texter30 and Casner,31 and others, have identified a variety of potential casing failures such mill defects, mishandling, borehole doglegs and corrosion. From such information, API has developed recommended practices for the care and use of casing32 and has defined the principal causes of trouble in otherwise properly designed casing strings, see below.
Principal causes of failure in otherwise properly designed casing strings A
. . . . . . . . .
Mishandling in mill, in transport and in the field Poor running and pulling practices Improper landing tension Improper cutting of field-shop threads. Poorly manufactured couplings for replacement Leaking joints Drill pipe wear Wireline cutting from swabbing, etc., and Corrosion.
Principalcauses of connection failures B
c
Fig. 11-Longitudinal imperfections in new pipe. Photo A shows part of an eight-foot long seam penetrati ng 0.110inch in a 0.217-inch wall. Seam was detected by magnetic particle inspection; depth was measured by grinding as shown. Photo B shows internal grooving in seamless pipe caused by pieces of hard metal adhering to the plug. The external longitudinal gouge in Photo C could be mill or transit damage.
sticking tendency may also increase because of the disturbance and reformation of filter cake caused by some preflush fluids, change-over of fluids and/or mechanical cake removal techniques. Things to remember sticking are:
regarding
differential
pressure
. Sticking occurs opposite permeable formations, particularly where pressure is depleted and/or high mud overbalance pressure exists
12
. . . . . . . . . .
Under (or over) tonging Dirty threads, galled threads Improper engagement (cross-threading) Excessivemaking and breaking Improper joint inake-up at mill Casing ovality or out-of-roundness Improper cutting of field-shopthreads Wrong thread compound or mis-application Over-tensioncasing, and Dropping the string.
A survey conducted by the API Southern District Tubular Goods Committee a number of years ag033 revealed that over 80% of tubular string failures occurred in the connections. Common causes of connection leakage under external or internal pressure as identified by API/2 are also shown in the above table. Most of these causes for leaking joints can be avoided through proper inspection and make-up practices, many of which will be discussed in the next article. WORLD OIL
1977
Mill defects in casing. Imperfections may be found in new casing as delivered by a mill. Such imperfections, shown approximately in decreasing likelihood of occurrence are as follows:
Defects found in new casing
. Gouges
. Seams . Laps
. . . .
. Eccentricity . Rolled-in-slugs
. Pits
Plug scores Weld area cracks External, longitudinal cracks Upset, transverse cracks
Casing joints containing such imperfections may be identified and segregated by non-destructive testing and inspection techniques. Examples of the above imperfections are shown in accompanying photographs taken during field inspections, Figs. 10-13. Although such imperfections may not actually lower a casing joint's burst, collapse or tensile strength below acceptable limits because of size, orientations, etc., API conservatively considers an imperfection to be a defect if it penetrates deeply enough so that less than 87~% of specified wall thickness remains. However, if the imperfection can be removed by grinding and the remaining wall thickness is equal to or greater than 87%% of the specified wall thickness, the joint is considered to meet API specifications. Otherwise the portion containing the defect must be cut off. The remaining joint continues to meet API specifications if it is within one of the permitted API length ranges. API specifies that high strength casing (P-llO) be inspected by non-destructive test methods at the mill. Imperfections that penetrate over 5% and less than 12%% of the wall thickness must be removed by grinding. Coming next month: Casing inspection and handling, joint make-up, use of thread compounds, hydrostatic pressure testing and landing practices.
A
';~
) B
C
Fig. 12-Types of cracks occasionally found in new pipe. Photo A is a longitudinal, external crack detected by magnetic particle inspection. The example in Photo B illustrates a transverse crack on the pipe upset with a grind mark showing penetration. The etched and enlarged sample in Photo C is a wall cross section through an arc weld with a hook-crack that has penetrated the pipe 00. This is caused by a layering in the plate edge that turns toward the surface (10 or 00) during welding.
Fig. 13-Example of eccentric pipe that failed in collapse because one side was too thin.
.
LITERATURE CITED 'Farrisl R. F. "Method for Determining Minimum Waiting-on-Cement Time,' Trans. AIME (1946), 165, pp. 175-168. , Bearden, W. G. and Lane, R. D. "Engineered Cementing Operations to Elimmate WOC Time," API Drilling and Production Practice (1961), l' 17. , Evans, G. W. and Carter, L. G., "Bonding Studies of Cementing Compositions to Pipe and Formations," API Drilling and Production Practice (1962), p. 72.
· Becker, iI. and Peterson G., "Bond of Cement Compositionsfor
Cementing Wells," Proc..::,].. Sixth World Petroleum Congress, Frankfurt, Germany, June 10-26, T~3. · Bearden, W. G., Spurlock", J. W. and Howard, G. C., "Control and Prevention of Inter-Zonal ~Iow," Journal of Petroleum Technology (May 1965), pp. 579-584.
· Evans G. and b
Carter,
G.,
"New
Technique
for Improving
Cement
Bond,"
API rilling and Production Practice (1964), PI'. 33-38. 1 Scott, J. B. and Brace R. L., Coated Casing-A Technique for Improved Cement Bonding," APi DrillinK and Production Practice (1,966). PI'. 43-47. 8 Ferd W. H., Pilkington P. E. and Scott, J. B., "A Look at Cement Bond Logs," Journal of Petroleum Technology, June 1974, PI'. 607-61'7. · Oliphant, S C. and Farris, R. F., "A Study of Some Factors Affecting Gun Perforating," Trans. AI ME (1947), 170, PI'. 225-242. I. Morgan, B. E. and Dumbald, G. K;, "A Modified Low-Strength Cement," Trans. AIME (1951'), 192, PI'. 165-1/0. 11Godfrey, W. K., "Effect of Jet Perforating on Bond Strength of Cement," Journal of Petroleum Technology (November 1968), PI'. 1301'-1314. 12Ben, W. T. and Shore, J. B., "CasinK Damage from Gun Perforators," API Drilling and Production Practice (1964), PI'. 7-14. "Godfrey, W. K. and Methven, N. E., "Casing Damage Caused by Jet Perforating," Paper SpE 3043, 45th Annual Fall Meeting, Houston, Oct. 4-;, 1970. .. Cheatham, Jr., ". B. and McEver, J. W'l" "Behavior of Casing Subjected to Salt Loading,_' Trans. AIME (1%4), 231, 1'1'. 1069-1075. ISMcCauley, T. V. "PlanninJI Workovers in Wells witlt Fault-Damaged Casing_-South Pass i!1ock 27 I"ield," Journal of Petroleum Technology (July 1974), p. 739. I. Roberts, D. L., "Shear Prevention in the Wilmington Field," API Drilling and Production Practice (1953), p. 1'i6.
WORLD OIL
1977
11Suman, G. O. Jr., "World Oil's Sand Control Handbook," Gulf Publishing Co. (1975). 18Suman, G. O. Jr.\.. "CasinR Buckling in ProducinJt Intervals," Petroleum Engineer, (April 19/4), p. 36. .. Schuh, F. J., "Failures in The Bottom Joints of Surface and Intermediate Casing Strings," Journal of Petroleum Technol0y,y, January 1968, PI'. 93-1\)1. '0 Owsley, W. D., "Improved Casing Cementing, , The Oil and Gas Journal, Dec. 15, 1949. "Dellinger, T. B. and McLean, J. C., "Preventing Instability in PartiallyCementea Intermediate Casing Strings," SPE Paper 4606 !,resented at 48th Annual Fall MeetinJI SPE of AIME, Las Vegas, Sep. 36-Oct. 3, 1973. " Dalrymple, D. H. Personal Communication. " Calvey, H. J., "Casing Designs and Programs Considered in the Anadarko Basin," Paper SPE 3909, 1972 Deep Drilling Symposium, Amarillo, Sept. 11-12, 1972. "Evans, G. W, and Harriman D. W., "Laboratory Tests on Collapse Resistance of Cemented Casing,'! SPE Paper 4088, 47th Annual Fall Meeting, San Antonio, Oct. 8-11, 1972. soHelmick, W. E. and Longley, A. J., "Pressure Differential Sticking of Drill Pipe and How It Can Be Avoided or Relieved," API Drilling and Produc/lon Practice (1957), PI'. 55-61. 26Outmans, H. D., "lVlcchanics of Differential Pressure Sticking of Drill Collars," Trans. AIME (1'958), 213, PI'. 265-274. "Outmans, H. D., "Spot Fluid QUIckly to Free Differentially Stuck Pipe," The Oil and Gas Journal, July 15, 1974, PI'. 65-68. ,. Barkis, B., "Primary Cementing, the Critical Period." B&W Publication. 29Annis, lvl. R. and Mona~han, P. H., "Differential Pressure StickingLaboratory Studies of Friction Between Steel and Mud Filter Cake," Journal of Petroleum Technology, May 1962, PI'. 537-543. 30'texter, H. G., "Oil-Well Casing and Tubing Troubles," API Driling and Production Practice (1955), p. 7. " Casner, J. A., "Care and lIandin/( of High-Stren/(th Tuhular Goods," API Drilling and Production Practice (1196'r), PI'. 169-1'76. ::2API Recommended Practice for Care and U!"c of Casing and Tubing," API RP 5Cl, Tenth Edition, March 1975. "Oxford, W. F., "API Southern District Tubular Goods Committee Summary of Inspection for Period Jan. 1, 11963to Jan. I, 1964," Houston, March 1966.
13
Cementing oil and gas wells Part 2-Casing inspection and pipe handling methods, including thread make-up control, hydrostatic testing, landing practices George o. Suman, Jr., President,and Richard C. Ellis, Project Engineer, Completion Technology Co., Houston 15-second summary How electronic inspection at the mill, pipe yard or rig site finds serious metallurgical defects. Pipe handling discussion tells why torque cOlitrol alone is inadequate for thread make-up. Axial load in slips is explained as are hydrostatic rig floor tests for connection leaks and landing practices to correct for future load changes. HIGHER EQUIPMENT and service costs and the trend towards completion of iWells in deeper, more severe environments emphasize the need for strict attention to casing quality control and handling before cementing. In one study, over 5% of 33,000 casing joints inspected did not meet API specifications because they contained defects. In another example, rig floor testing revealed 1.4% of the joints tested leaked. This article tells what can be done to prevent the running of defective casing, including: i~ Casing -inspection methods: Need for, and results of, field casing inspection, and techniques and principles of non-destructive inspection in the pipe yard, rig site or mill
Fig. 14-Magnetic particle inspection defines mill imperfections that are otherwise not visible. Before-and-after photo of 5V2inch, N-aocasing segment, shows how seam in the metal was detected by inspection.
LONGITUDINAL
IMPERFECTION
SEARCH COIL TRANSDUCER
i~ Pipe handling: Recommended procedures for transporting and running casing; rig floor practices to avoid slip and tong damage ~ Casing make-up: Functions of threads and thread compounds in sealing-off fluids; factors affecting torque
recommendations, and systems to control make-up .for optimum
connection
performance,
and
~ Rig floor connection testing: Internal and external hydrostatic tests for leakage; how thread configuration affects test application; casing landing practices. Many casing problems are directly related to casing condition existing prior to cementing/a, 32,34,35 usually as a result of: Metallurgical flaws, damage in transit or on location; improper connection make-up, or poor running practices. CASING INSPECTION Casing inspection can mean anything from visual rig crew checks of pipe body and threads while running, to extensive non-destructive inspection (NDI) of each joint, including threads and couplings. 14
~G'
MAGNETIC SOURCE
1([lIQ PIPE
Fig. 15-Schematic of transverse electromagnetic-diverted-flux, search coil (EDFSC.) system illustrates how flux diversion detects seams, etc. oriented along pipe axis. Seams, rolled-in-slugs and eccentricity are some imperfections that are not visible without aid of some type of NDI; an example is shown in the with-and-without magnetic particle inspection of the same section of pipe, Fig. 14. Obviously in this example, visual inspection alone would not be adequate. The cost for NDI of pipe body and end areas varies with location and other factors. But, generally, cost for complete inspection of casing is less than 10% of total casing cost, as shown in the table on following page. WORLD OIL
1977
Note: API defines a defect as any imperfection that effectively reduces the wall thickness of any grade pipe to less than 871'2% of the specified wall thickness.36 In lower casing grades, no action is required for imperfections that do not classify as defects; however, in highstrength casing (such as P-11 0) an imperfection penetrating 5% or more of the specified wall thickness must be removed by grinding. Only such "imperfections" are included in the table,38 Over 80% of the problems included in the a:bove study originated in the mill; the remainder was handling damage. Casing of all grades was included in the study. However, grades were mostly N-80 or higher, as shown helow:
Inspection costs vs. casing costs
Ca.sing Size,
In.
Percent of casing cost, f.o.b. pipe mill**
Typical Inspection costs per length, $* Total cost End Body-
13% 9% 7 5!h
wall
area
19.00 14.70 13.90 12.45
5.50 4.95 4.70 4.40
per foot* K-55
N-80
p-no
4.23 5.06 7.41 9.60
2.48 3.68 4.37 5.32
2.59 3.60 4.39
0.612 0.491 0.465 0.421
* Range3 casing, approx. 40I lengths. ** Typical casing costs, Jan. 1977.
Number of defects by casing grade Need for inspection.
Pipe manufacturers have extensive quality control procedures, and API specifications call for nearly 30 separate tests during the manufacture of casing.36.37.38 Most manufacturers utilize in-line NDI equipment. And such inspections are required for P-1IO grade casing. However, a study of an independent service company's casing inspection statistics, compiled over a 12-month period in 1975/1976, shows that 1,861 joints of a total 33,562 inspected (5.54%) failed to meet API specifications, see table below:
Grade K-55 & H-40.................... Percent. . . . . . . . . . . . . . . . C-75, N-BO, S-95.. . . . . . . . .
:::::: Percent.. .. . . . . . . . . . . . . . . . . . . . . . P-llO, other. . . . . . . . . . . . . . . . . . . .
Percent........................ . Total.. .. .. .. .. .. .. .. .. .. .. .... Percent........................ .
No. lengths Inspected
Total defects
Body defects
2,536 100.0 24,001 100.0 7,025 100.0 33,562 100.0
82 3.2 1,377 5.7 402" 5.7 1,861 5.5
41 1.6 719 3.0 293 4.2 1,053 3.1
End afea, othef defect 41 1.6 658 2.7 109 1.6 808 2.4
" An additional821 "imperfections" were noted for this grade. Industry efforts. It is estimated that only 15-20% of oil field casing and tubing is currently inspected by inde-
New casing inspection results* Location,type of Imperfectlon** Casing Size
No.lengths Inspected
External bodywall
4!h 5 5!h 7 7% 9% 10% 11% 13% 16 20
934 4,629 8,369 6,874 2,772 7,147 1,416 75 1,109 114 123
116 287 354 271 124 305 36
Total
33,562
1,497
Casing Size
Seam Ext Int
Lap Ext Int
71
11 117 156 99 21 60 2
Internal bodywall
2 2
Connection
Drift,othert
52 25 26 4 20 4
2 266 109 94 64 220 22
4 4t 22t 12t 25t
1 .... ....
22 1 1
1 2
132
801
70
Thlnwall, eccentric
Total Imperfect
33 17 104 1 26 1
182
Total defective lengths
118 642 509 517 205 596 63
40 467 373 259 152 479 59
26 3 3
26 3 3
2,682
1,861
Plntt Mfg Hdg
Coupllngtt Hdg Mfg
Descriptionof bodywall,connectionImperfections
4!h 5 5!h 7 70/8 90/8
10% 11%
86 64 78 162 14
3 10 1 3
41 4 4 2 2
1 24 43 46 14 53 20
6 1 1 9 1
Pit Ext
Int
23 31 51 6 10
3 2 6 5 1
Gouge Ext Int 32 11 24 6 2 10
1
130/8
16 20
Total
Roll-Inslug Ext Int
575
17
466
53
2
..
204
18
121
17
85
Crack,cut Ext Int 1 12 14 5 3 10
12
1
1 ..
..
8
46
19
3 3 1
5
2
7 23 1 6 55 9
101
2 4 41 57 23 94 13
251 37 18 34 49
17
5 1 1
251
396
4 8 18 1 22
53
* Source: AMFTuboscop,ereports to several operators on new casinginspection in various yard and field locations, 1975/1976. ** SeeAPI definitionof 'imperfection"and"defect" in text. t Includes1-3 lengths of wronggrade or wrongweiht. tt Analysisof connectiondamage by manufactureror 10handling.
WORLD OIL
1977
15
pendent service companies utilizing NDI techniques. One possible reason that manufacturers' NDI does not discover all problems is that sensitivity of plant equipment is adjusted to detect defects, as defined by API, that penetrate 12~% or more of the specified wall thickness on a "go, no-go basis," whereas, an independent inspection company usually adjusts equipment to a higher level of sensitivity, then relies on detailed examination of the imperfection to determine if it is .within API specifications.36,
38
Non-destructive inspection techniques. The semiautomatic non-destructive inspection units that many inspection companies have developed feature: Two electromagnetic-diverted-flux, search coil (EDFSC) testing systems; a radiation wall thickness measuring device; and an electronic metal comparitor. These systems are used to detect imperfections in the pipe body as the pipe moves through the NDI unit at a constant speed. Units are available that can handle tubulars of 1.315 to 14-inch aD. Various units have inspection or scanning speeds that vary from less than 30 seconds to over 60 seconds, per Range 3 length. Most units are portable and can be used at the well site, pipe yard or mill. Principles of EDFSC systems are illustrated in Figs. 15 and 16. A magnetic flux field is induced into the wall of the pipe. This field flows in one direction and diverts around imperfections. Flux diversion or leakage occurs through air near the pipe surface. Search coils, cut through these diverted flux fields and generate electrical impulse. The recorded magnitude and pattern of these impulses indicate imperfections. A large number of variables affect EDFSC sensitivity, i.e. shape and orientation of an imperfection; magnetic flux field energy level; shape and orientation of the search coil with respect to the imperfection and direction of diverted flux field. Specific combinations of the controllable variables are proprietary information of inspection companies. Wall thickness of 0.75-inch or more reduces EDFSC sensitivity to internal body wall defects. In critical applications where thick-wall casing is used, additional inspection with internal magnetic particle techniques, or other special methods, may be required. Radiation wall thickness measuring is an efficient method for inspecting oil field tubulars for general (not localized) wall thickness variations like eccentricity within a joint, or change of weight betiween different joints of the same grade. This system is not used to detect cracks, pits or other surface imperfections. The radiation source and detection equipment does not come in contact with the pipe being inspected. There are three common arrangements of source and detector for gamma-ray thickness gaging, Fig. 17.40 These systems are sensitive to distance between pipe wall and source, between source and detector, and between detector and pipe /Wall. Precise alignment must be maintained to avoid inaccurate readings. Pipe movement vs. rotational speed of the gamma-.ray unit affects the percentage of pipe actually scanned, as the path of investigation is a helical trace around the circumference, like the stripe on a barber's pole. Rota16
SEARCH COIL TRANSDUCER ELECTRIC COIL
~, II
-:':-
~
_ \.. TRANSVERSE IMPERFECTION
LONGITUDINAL MAGNETIC FIELD Fig. 16-Schematic of longitudinal detect transverse imperfections.
ROTATION
EDFSC system used to
GAMMA SOURCE
OETECTOR
/
SHIELD
RADIATION BEAM SINGLE-WALL BACKSCATTER
THROUGH DOUBLE-WALL
SHIELD THROUGH SINGLE-WALL
Fig. 17-Radiation wall thickness measurement uses a highly focused beam to irradiate the casing wall as system rotates around pipe. Drawings indicate three common arrangements of source and detector (after Kahil).'.
tional speed of the single-wall system can be faster than backscatter or double~wall systems. However, all three systems can detect general wall thickness variation. Electronic metal comparitors electronically compare the grade of pipe being inspected with a grade standard. This system induces eddy current into the pipe which is adjusted until balance is achieved with the standard. Then as the pipe is inspected, variation in the balance is an indication of metallurgical change. The technique is very sensitive and even different heats of pipe of the same grade can be detected. This comparison is a quick and easy, positive identification of grade change. However, it is only qualitative. It does not define either magnitude of metallurgical change or direction of change, i.e. increase or decrease in grade. This system is most commonly used for inspection in the yard and at the rig, where mixing of grades may have occurred, or for inspection of used tubulars. End area magnetic particle inspection is a procedure separate from those performed by the NDI unit. This method is based on the same diverted magnetic flux principles of the EDFSC system, except that dry iron powder that is "sprayed" onto the surface is magnetically attracted to flux leakage occurring at imperfection. These particle accumulations are visually located. The end area being inspected must be cleaned with a solvent, to a dry surface, to prevent powder accumulations on moisture, grease, thread compounds, etc. Prior to inspection, threads should be visually examined for tears, cuts, shoulders or other imperfections breaking the contour of the threads; these are also defects.41 And, while WORLD Oil
1977
it is not always essential, sand blasting will improve magnetic particle inspection sensitivity. How to find imperfection depth. Further examination of imperfections is required to determine if they arein fact-a defect, as"defined earlier. When NDI units indicate presence of an imperfection, magnetic particle inspection, as was described, is frequently required, to locate the imperfection in the pipe body. Once located, imperfections on the pipe's outer diameter are measured by grinding to the base of the imperfection. If 87Y2% of the specified wall thickness remains, in any grade, the pipe complies with APJ.36 However, with high strength (P-IlO) casing, any imperfection ,that penetrates 5% or more of the wall thickness must be removed by grinding.38 The ultrasonic wall thickness spot check device is usually used to determine remaining wall thickness. Unfortunately, there is no commonly used, non-destructive method to thoroughly examine imperfections on the internal diameter surface. Although this is a disadvantage, it is not a significant problem as most surface metallurgy imperfections in ne.w casing occur on the outer diameter as a consequence of the manufacturing process. For example, less than 5% of the defects in the major study previously discussed are internal. . Ultrasonic wall thickness instruments use a compression-wave source and a detector to spot check wall thickness. These instruments can be accurate to + O.005-inch when the sonde is properly coupled to the pipe. In application, a liquid couplant-like water, oil or antifreeze that contain no gas, solids or fibrous materials -is applied to the clean pipe surface and the ultrasonic sonde is pressed firmly against the moistened pipe. Length, diameter, hardness. Mechanical measurements are made to verify that joint lengths meet industry specifications and/or will be satisfaotory for a specific application. And occasionally when a larger than standard drift diameter is desired, special drift mandrels are used to cull the pipe stock. This and other special inspections requested by an operator should be performed in the pipe yard or mill to avoid transporting a large number of unusable lengths. Hardness testing is commonly used to verify a restricted range of yield strength for casing that is to be used in sour (H2S) environments (except C-75 grade casing which has been manufactured for this application). 39 Such tests can he conducted anywhere. However, consistently accurate data are difficult to obtain in less than lab type environments. Accuracy will depend on surface preparation, clamping systems, etc. Significant industry effort !Was expended to develop C-75 grade materials for severe sour gas environments. Methods for specifying and inspecting these types of materials are available in the literature.42 Identification bands. Pipe thaJt has been inspected is usually identified by stenciled information and color coded bands, above right. The stencil usually states who did what type of inspection and when. While this is not an official code, it represents common practices used by most inspection companies. WORLD OIL
1977
Recommended inspected tubular goods identification Type paint band
Location
Indicates
White
Near box
Meets API specs
Yellow
Near box
Imperfections not repaired API Std 5AX
Yellow and white
Near box
Imperfections repaired as per API std 5AX
Blue
Near box
ID imperfections, depths cannot be measured accurately
Red
Near box
ID or OD defects that fail API acceptance specs
Red
Around coupling, adjacent to threads
Defective box or pin
Orange, zig-zag pattern
Near coupling or box end
Length fails to pass API drift mandrel
as per
Where to inspect pipe. The most common locations for non-destructive casing inspection are pipe yards and well sites. Occasionally independent company inspection is conducted at the pipe mill. Inspection close to the pipe source cuts the cost of transporting defective pipe. However, well site inspection minimizes the running of casing that was damaged after yard or mill inspection. Thus, choice of location 'should be based on operator control of pipe prior to well site delivery. Lack of space at the !Well site may preclude use of NDI. However, some type of inspection is required at every well, if it is only cleaning and visual inspection by the rig or casing crew and application of compound to pin and coupling threads prior to running. In any case, Planning for well site equipment and pipe rack arrangements should include the well site inspection program. When NDI units are to be u'sed at the site, the pipe rack arrangement and casing location should he compatible with the inspection program and NDI unit capability. Some units have single pass capability while others require pipe to pass through the unit in both directions. An extra pipe rack may simplify the job. Also, it is extremely difficult to do a good inspection job on casing ends that overhang the mud pit. Preliminary planning greatly reduces time required for well 'site inspection. Inspection equipment must be maintained in excellent operating condition to provide consistently accurate results, and people operating the units have to be competent. The operator should demand optimum performance. At least two of the larger service companies provide technical seminars for operating company personnel. CASING HANDLING During the past 40 years, recommendations for proper care and use of casing have been defined and encouraged by APJ.32 But casing is still subjected to damaging handling practices in many locations. Some of the more important handling practices are shown in the following table. More complete handling procedures are documented in the literature.31. 32, 43
Recommended casing handling practices . Move casing only when thread protectors are in place 17
.
Store or rack casing only on wooden or metal surfaces of rocks, sand or other debris
free
SLIPS
. Use spreader-bar and choker-chain arrangement near each end to prevent crushing when handling bundles of casing joints with a crane .
Do not unload pipe by dropping. When unloading by hand, use a rope sling to control pipe momentum and prevent pipebanging after rolling down the skids. Even with protectors in place, pipe threads can be damaged
SLIP' BOWL ANGLE (a)
. Avoidall rough handling. Running casing. Design details identifying various weights and grades for each section of the string should be available. If weight and grade of a joint cannot be clearly identified, it should be set aside until positive identification can be made. Casing ID can readily be checked (drifted) as it is pulled into the derrick, by dropping a drift mandrel through the joint. Drifting at this time removes any debris that could interfere with cementing equipment. It also prevents the running of a joint with a restrictive ID. For short, lightweight, casing strings where collar-pull elevators are used, the bearing surface should be inspected to be sure that the load will be uniformly distributed. Side load on a collar could "jump" the collar off. Slip-type elevators and spiders are recommended for long casing strings. It is critical that the casing be gripped so that no permanent deformation results from the gripping forces. Axial loads in slips. Where casing is gripped by wedges or tapered elements with slip-type equipment, as in Fig. 18,44 axial load (F) due to casing lWeight tightens the gripping elements with radial force (W) due to wedging action of slips in the tapered bore. Critical axial load (Fe) for slip-type equipment, where permanent deformation of the casing occurs, is determined as follows: 45
Fe (lbs.) = C X A X
(T
Where (T
= yield
strength
of the casing,
psi
A = Cross sectional area of the pipe body, in2
[
rK
rK
2
1/2
= Crushing factor = 1/ 1 + L + (L ) J And: r = Outside casing radius, in. L = Slip gripping length, in. K = Transverse load factor = 2.636, based on acC
cepted API slip bowl taper of 2 inches per foot and minimum coefficient of friction (0.2) for lubricated hardened steel against hardened steel at the slip-bowl interface.
For a given size, weight and grade of casing, slip length (L) is the primary variable controlling critical load. Example calculation: For 9%-inch, 47 pound/foot, N-80 casing, using 14-inch slips:
=
A 13.57 in2 C = 0.606 (T
= 80,000psi, and
Fe= 0.606 X 13.57X 80,000= 657,000pounds. Slips used for heavy casing 'Strings should be checked 18
RADIAL FORCE (W)
. AXIAL LOAD (F)
Fig. 18-Slip critical axial casing.
configuration and symbols used in calculating load where radial force starts to deform the
for adequate length and bearing area to minimize damage. Radial force (W) is related to axial load (F) by slip geometry and the coefficient of friction (p.) between slip and bowl. This relationship is
W (lbs.) Where:
I-p.tan.aX
= p.+ tan a
F
= Slip bowl taper angle, Fig. 7 po= 0.2 (usually)
a
Slip marks damage the integrity of high strength or sour service casing. To minimize this damage, slips should be clean, in good repair and they should be selected to fit casing OD closely. In rare instances where odd-size casing is required, special slips should be provided. Slips should all lower together and seat properly in the slip bushing or bowl. Slip marks should be examined periodically for uniform impressions.
CASINGMAKE-UP I TORQUE The thread protectors should not be removed until joint is ready to be stabbed into the box end of the preceding joint. The joint then should be lowered carefully to avoid thread damage. Vertical alignment should be maintained and the casing should be rotated very slowly at first to assure thread alignment. Tong dies should be examined for wear prior to running casing. The back-up line should be positioned on the back-up post so tong gripping surfaces exert an even load and minimum bending force on the casing. The back-up line must be lined up at a 90-degree angle to the power tongs to obtain an accurate indication from a torque gage that measures tension in the back-up line. The torque gage should be reliable and in calibration so that irregularities in torque required for casing make-up can be observed. The development of power tongs in the 1940s provided the means for improving make-up practices as well as reducing rig time required to run casing. However, the WORLD OIL
1977
VANISHING POINT
\c
POWERTIGHT
! I I I
TURNS OK
BEARING PRESSURE
HANDTlGHT
API ROUND THREAD
MAKE-UP OPPOSITE ANYiPART
/
OF STAMP OK
TRIANGLE STAMP[> ,
HANDTIGHT BUTTRESS THREAD
Fig. 19-Thread configuration and basic make-up positions of API 8 round and Buttress threads (after API Spec 5A)." practice of using torque alone as the means for make-up control was never intended by API. The two most important factors that influence leak resistance of threaded pipe joints were identified, over 30 years ago, as joint make-up and thread compound.43 The basic sealing principle for API 8 round threaded connections, Fig. 19,46 is that contact (bearing) pressure between pin and box, produced by make-up, forms several metal-to-metal seals, and that solids from thread compound fiU the void space between the threads. These solids are required to transmit bearing pressure from one threaded surface to the other. The connection seal is maintained only as long as bearing pressure is greater than the internal or external differential pressure. Sealing ability-as well 8.'Sthe influence on friction-of different thread compounds varies greatly. Pressure tests have shown that marked variation in sealing ability exists between different brands of API Modified thread compounds as well as with specialty compounds.46 Non-API connections. Several different types of nonAPI tubular connections are commonly U'sed. Descriptions of these have been reported in the literature,48 and latest data on premium thread designs are available from manufacturers or COMPOSITECATALOG. Such connections employ several different basic types of thread designs. They can have both shouldering and non-shouldering connections with "metal-to-metal" seals, while other connections rely on a 'Supplementary, resilient Teflon seal. Obtaining a pressure seal in connections that rely on metal-to-metal sealing requires make-up, to force the pin and box mating surfaces together. Theoretically, the pin should be stressed to about the yield point to obtain maximum leak resistance. This keeps the connection in the ela:stic stress range and produces the maximum amount of bearing pressure between mating surfaces for leak resistance.49.5o A precise make-up procedure is required to achieve these maximum leak resistance conditions. API torque recommendations. Although it was never intended, development of power tongs made it very convenient to use torque as the only guide for make-up control. However, variations in thread design, surface finish, thread compounds and the size, weight and grade of pipe all interact and influence make-up torque. WORLD OIL
thread pullout strength formula was several variables that affect make-up
torque. 51 And when API conducted tests that measured ~!:tTW~,,~~RE~D I
MAKEUP
The API round thought to contain
MAKE-UP
1977
torque required to make up API 8 round threaded connections lubricated with API Modified thread compound, it was found-emperically-that these torque values were about 1% of the calculated pullout strength. Therefore, the recommended torque values listed in API RP 5CI are calculated from the following relation:
Torque (ft. lbs.)
= 0.01
Minimum
joint strength
(lbs.).
API RP 5C1 further states that torque W8.'Sselected to give optimum make-up of API 8 round connections under normal conditions and should be considered satisfactory only if the face of the coupling is within plus or minus two thread turns of the last thread scratch (vanishing point), Fig. 19. When using API RP 5C1 recommended make-up torque tables, use API Modified thread compound and observe the make-up position of each connection. For Buttress threads, API recommends:
1. Determine torque required to make-up each of several connections to the proper position, then 2. Use that torque to make-up the balance of the same weight and grade pipe in the string, but 3. Continually observe make-up position for verification of proper make-up. Buttress thread connections have triangles stamped on the pin ends. Proper make-up is achieved when the coupling face is opposite any portion of the triangle, Fig. 19. Effect of thread compounds. Torque required to properly make-up connections depends primarily on friction between pin and box threads. For clean, damage-free threads, make-up torque is significantly affected by type of thread compound. Use of different compounds can cause make-up torque variations of up to 500%.52 Such large variations indicate that, to establish maximum bearing pressure between pin and box mating surfaces-and not risk overstressing pin or box-a more accurate means of measuring make-up (than torque alone) is required. Two methods for making such measurements will be discussed. An API subcommittee is currently reviewing thread compound standards, attempting to develop more precise standards for friction and leak resistance performance. Careful selection of compounds for each set of conditions, on the basis of friction and leak resistance characteristics, is encouraged. These characteristics should be clarified by discussions with both pipe and Iu b r i can t manufacturers. Make-up control (Torque-Turn). During 1963, the API Southern District Tubular Goods Committee conducted a survey of tubular string failures.33 This survey (still the only comprehensive study published) showed that 86% of reported casing failures occurred in connections. In 1967, Exxon
Torque-Turn
began
licensing
its newly developed
make-up control device,
47.49.52
an auto-
mated make-up monitoring system for API type connections that cross-checks torque with turns (make-up position) to determine connection acceptability. Make-up control with this system involves pre-setting 19
of reference, minimum and maximum torque, and low, minimum and high turns. These torque and turns settings vary with size, weight and grade of casing, thread compound and type of connection. Specific setting are considered proprietary information of various licensees. The system can accommodate single-end or double-end connection make-up. Double-end make-up is used when the mill provides collars separately or "hand-tight" (floating) which need to be made-up on the rig floor. The system is available in most U.S. steel mills for installing collars, if specified. Where the system is to be used on the rig floor, collars made-up in the mill should utilize the same control so that the first-half of the connection is not disturbed. A new make-up control system recently developed by AMF Tuboscope provides a method to evaluate the condition of pin and box threads before casing is run into the well, and measure connection make-up. 53 To apply AMF's Torque at Proper Engagement (TAPE) control system, protectors are removed and threads are cleaned. Then, API ring and plug gages are run on both threads to the hand-tight plane using a power driven tool with controlled torque, Fig. 20. The location of the gage on the threads is checked per API Standard 5B. Torque reference marks are inscribed around pipe circumference and coupling if the relative position of the hand tight plane agrees with API. Thread compound is applied and cleaned thread protectors are replaced. When casing is run, each connection is made up to a specified torque load and the distance between pipe and coupling reference marks is checked with a special gage card on which the mark shows in an "acceptance window" when proper make-up position is achieved, Fig. 20. Torque is recorded on a chart and used to verify proper thread engagement and make-up. This new development will be available initially in California. RIG FLOOR LEAK TESTS Hydrostatic testing of casing connections on the rig floor is a technique used to prove leak resistance of connections. Tools are currently available that provide for internal testing of up to 8%-inch casing, and external testing of up to 16-inch casing. Hydrostatic tests have been proven capable of detecting (on the surface) connections that will leak under pressure. Such a detectable leak could easily result in a casing leak downhole. There are advantages and disadvantages of both internal and external testing, for example: The small fluid volume used in external testing increases sensitivity and shortens test time; however, visual inspection of a leaking connection is not possible with external testing. Also, the internal system can test the entire joint. Connection geometry has a significant effect on whether a connection is more subject to leaking due to high internal or high external pressures. To prevent leakage, connection bearing pressure must exceed pressure differential from either direction. But the same pressure differential, in turn, has an "energizing" effect on the bearing pressure that can alter the true leak resistance of the connection. And this effect varies greatly with direc20
Fig. 2D-New make-up control system uses controlled-power unit, left, to run ring and plug gages to "hand-tight" positions to check pin and box thread quality. Reference marks, right, then are applied to pin and box, and make-up position is verified on the rig floor using calibrated window in special card, right (courtesy AMF Tuboscope).
P, I I
r
t
I I I I I I I I Ie
Q. ui a: ::> en en w a: Q.
:I)
P (EXTERNAL) CASING OD .. -c'
_____ I
I I
: I
""";'~"_. -, ,.. ,-,.-"",
B(BEARING PRESS. AT SEAL POINT)
I
.
T (PIN)
P(INTERNAL)
Fig. 21-Energizing effect of pressure applied across a connection. On the curve representing the thin-pin, thick-box connection in the drawing, B, is initial bearing pressure from make-up in the metal-metal inner seal, PE and p, are theoretical external or internal pressures required to initiate a leak at the seal, and e is a function of connection geometry. When thicknesses are nearly equal, as in API connections, e approaches zero and the energizing effect of pressure in either direction is not significant.
tion of the differential pressure and connection geometry, Fig. 21. External testing, for example, can be more effective in detecting leaks in premium type connections that have a metal-to-metal seal surface at or near the tip of the pin. Insufficient make-up (position-wise) due to damaged or defective threads or seal surfaces can result in low initial
bearing
pressure
even with
apparently adequate
torque. In such connections, the metal is much thinner in the pin than in the collar, at the sealing point. Therefore, higher internal pressure "energizes" the otherwise insufficient seal by expanding the pin into the box, increasing bearing pressure. Conversely, increase in external pressure has very little energizing effect on the seal, Fig.
21. In this thin-pin, thick-collar situation,
a lower
ex-
ternal pressure would detect the problem. Test procedures. For API, non-premium connections, in which pin and collar thickness difference is less significant, test procedures used may be of more importance than the test method, internal or external. The length of time that test pressure is held on the WORLD OIL
1977
connection varies widely in practice, as do opinions on the subject. Many leaks have not been detected in less .than 10 seconds, and many testers recommend that 10 seconds be the absolute minimum even in low pressure se.vvice. For pressures over 2,000 psi, 20-30 seconds (or more) would give. more reliable results. Leakage depends on time because of the tortuous path fluids may follow through voids between threads and/or because of the slow displacement of viscous but nonsealing thread compound. Use of a strip chart pressure recorder is a simple way to obtain a permanent record of connection testing. It allows development of more dependable test duration statistics. And the strip chart can be retained as a permanent record of test time and leaks found. Recommended test pressure also varies with application and with operator. Most testing companies recommend that test pressure be 80% of pipe yield pressure. And-attempting to duplicate downhole conditionssome testers recommend that pressure be applied and released at least once before performing the test, and that all testing be conducted with the connection in tension. Since there are no industry standards for hydrostatically testing casing connections on the rig floor, and
lengthening of casing as the piston effect causes more lengthening than the shortening effect of swelling (ballooning). This "stretch" is cemented in when the cement sets. However, swelling that increases casing diameter slightly may create a micro-annulus between cement and casing when pressure is released after cement has set. Because of an increasing awareness of bonding and micro-annulus problems, operators in certain geographical areas are reluctant to hold pressure on casing greater than the differential required to support the denser cement column in the annulus. In any case, it is necessary to anticipate changes in downhole conditions that may occur during well life to determine correct adjustments or landing procedure. Severe conditions such as arctic (permafrost), ultra deep, thermal or geothermal environments, of course, require even more careful evaluation and perhaps specialized landing practices. Coming next month: Cement slurry composition, classifications, types and availability of additives, applications in common downhole problems, special cements for special purposes.
'because practices vary widely,55 it is recommended that equipment eaoh job.
and procedures
be carefully
examined
before
CASING LANDING Casing landing practices should for each well to minimize chances during future ope.ra:tions. Practices field may not be appropriate for Three
variations
be specifically defined of buckling or parting effectively used in one another.
are usually implemented:
1. Normally, casing is landed in the wellhead in the position in which it was cemented, i.e. "as cemented" 2. It can be stretched
to increase tension, or
3. It can be slacked off to reduce
tension.
Which procedure is used and to what degree slack-off or tension is added is a function of anticipated changes in wellhead loading that will occur during the life of the well. Wellhead loading is affected by: Changes in temperature and pressure; internal and external fluid weight variations; and location of the permanent (and temporary, if any exists) freeze point (free point). Equations, useful nomographs and analytical procedures in the literature can be used to determine appropriate landing
procedures. 56.
51
'two methods that can be used to adjust wellhead loading offshore where ocean bottom suspension precludes use of conventional onshore landing practices are: Increase height of the primary cement column; and/or hold an internal pressure on the casing until cement
sets.58
Increasing height of cement is usually more economical as it requires less rig time. However, certain problem formations or lost circulation zones may not tolerate high cement columns. Holding internal pressure normally results in a net WORLD OIL
1977
LITERATURE CITED F. R., "Oil-well Casing Failures," .. Kettenbur~, R. . and Schmieder, API Drilling an Production Practices, 1945, p. 195. "Davis, S. H. and Nippert, H. W., "Why High-Strength Tubular Goods Fail" Oil & Gas Journal, April 13, 1964, p. 84. 3. "API Specification for Casing Tubing and Drill Pipe," API Spec SA, .Thirty-third Edition, March 1976. 31"API Specification for Restricted Yield Strength Casing and Tubing," API Spec 5AC, Tenth Edition, March 1976. 38"API Specifications for High-Strength Casing, Tubing and Drill Pipe," API Spec SAX, Tenth Edition, March 1976. 3. Hamby, T. W., Jr., Broussard, L. P. and Taylor D. B., "Producing Mississippi's Deep High-Pressure Sour Gas," JPT, June 1976, p. 629. 40Kahil, K. l?~ 'Automatic Nondestructive Testing of Oil Field Tubular Goods," ASME Paper 7S-Pet.42, presented at the Petroleum Mechanical Engineers Conference, Tulsa, Okla., Sept. 21-2S, 1975. 41"API Specifications for Threading, Gaging and Thread Inspection of Casing, Tubing and Line Pipe ,Thread," API Standard 5B, Ninth Edition, March 1974. '2 Swanson, T. M., "Experience With High Strength Steel Oil Field Tubular Goods, in Sour Service," presented at the Srmposium on Line Pipe and Tubular Goods, API 1976 Stand. Conf., Dallas, Texas June 1~-18, 1976 p. SS-4:3. '3 Kemler, E. N. "Factors Influencing the Leakage Resistance of Threaded Pipe Joints," API Drilling and Production Practice, 1946, p. 275. .. "Develol'ment of Casin", Handling Equipment for Ultra-Deep Gas and Oil Wells," report ava.lable from Varco Oil Well Tools, Box 6626, Orange Calif. .. Spiri, W. H. and Reinhold, W. B., "Why Drill Pipe Fails in the Slip Area," World Oil, October 1969. .. Grenawalt, J. J., Pallante N. L. and Roblin, M. J., "Relative Sealing Characteristics of Thread Compounds," presented at the Petroleum Branch ASME Meeting, Philadelphia, Pa., Sept. 17-20, 1967, also R&D report of Youngstown Sheet & Tube Co. 41Weiner, P. D. and True, M. E., "Unique Device Eliminates Leaks in API Connections," World Oil, July 1969. .. Anon, "1976.77 Tubing Tables" World Oil, January 1976. .. Weiner, P. D. and True, M. E., "A Method of Obtaining Leakproof API Threaded Connections in High-Pressure Gas Service," API Paper 926-14-M, presented March 1969. 55Eaton, B. A., "Detecting Leaks in Oil Field Tubular Connections," Worla Oil, September 1973. 51"Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties," API Bul 5C3, Second Edition, November 1974. 52Weiner, P. D. and Sewell, F. D., "New Technology for Improved Tubular Connection Performance," JPT, March 1967. .. "TAPE Control: The New Reliable Method of Evaluating Threaded Connections and Controlling Makeup," AMF Tuboscope Factsheet, Vol. 76, No.6. .. Hasha, M. H. and Snyder, R. E., "External Testing Finds Hidden Connection Leaks," World Oil, February 1971-. 55Kerr.. H. P., "Thread Leaks in Tubing and Casing Stringo," API Drilling and rroduchon Practice, 1965, p. 14. 55Cox, W. R., "Key Factors Affecting Landing of Casing," API Drilling and Production Practice, 19S7, Pl'. 22S-2S0. ., Chesney, A. J., Jr., and Garcia, J., "Load and Stability Analysis of Tubular Strings," Paper 69-Pet-lS, presented at the ASME Petroleum Mechanical Engineering Conference, Tulsa, Okla., Sept. 21~25, 1969. 51Dellinger T. B., and McLean, J., "Preventing Instability in Partially Cemented Intermediate casing Strings," Paper SPE 4606, presented at the Fall Meeting of SPE 01 AIME, Las Vegas, Nev., Sept. 30-0cl. 3, 1973.
}
21
BASIC CEMENT PROPERTIES
Cementingoil andgaswells Part 3-How basic cements and additives can be tailored to give desired properties for completion and remedial operations
George o. Suman, Jr., President, and Richard C. Ellis, Project Engineer, Completion Technology Co., Houston 10-second summary API's classification of basic cements is presented, commercial additives are listed and effects of slurry formulation on properties such as thickening time, compressive strength and density are discussed. The function of various cement compositions in typical and special downhole applications is explained.
"Neat" oil well cement-the basic powdered material, without additives-is commonly called "Portland cement" after the small town in England where it was first made. It is manufactured from limestone, clay, sand and iron ore, which are finely ground and blended, then fired in a rotary kiln to about 2,600° F. These materials semi-melt into glass-like balls or clinkers of complex calcium silicate which then are re-ground with gypsum. Portland cement consists primarily of: Tricalcium silicate, dicalcium silicate, tricalcium aluminate and tetracalcium aluminoferrite. In addition, it contains free gypsum (CaS04) magnesia (MgO) and lime (CaO).59 The percentage of these components in the final blend can affect early strength, sulfate resistance, hydration, swelling and cracking during cure and/or rate of hardening. API has established cement classes, with maximum percent of the above chemical components designated. GO API has developed physical requirements as well, including: water addition, soundness, fineness, minimum thickening time, minimum compressive strength and free water content. Soundness is a measure of the expansive properties of a cement, and fineness is the particle size to which a clinker is ground. Particle size can affect setting time, early strength and water addition. API also has specifications for certain additives such as bentonite, barite and fly ash. Cement classifications provided by API for nine classes of cement allow for various pressure/temperature conditions, early strength, sulfate resistance, adaptability to modification with accelerators and retarders and availability, as follows:
API cement CEMENT SLURRY composition can be tailored-by selection of the correct API-classified cement, proper use of one or more additives and addition of the desired volume of water-to meet demands of nearly any modern well completion. Examples of applications where special cement formulations may be needed are: High pressure gas containment, squeezing and plugging, extreme temperatures and lost circulation conditions. This article covers these important considerations with discussions of:
Class A B C
~ Cement additives: A listing of what's available under what trade name; how additives are used to develop slurry properties such as fast or slow thickening time, high or low density and fluid (filtrate) loss ~ Properties of set cement: How cement composition affects strength and expansion characteristics, and :~ Special cements: A discussion of salt cement; ulations for high/low temperature conditions. 22
form-
Depth range,
ft.
.
0-6,000 0-6,000 0-6,000
0
6,000-10,000
E F G
10,000-14,000 10,000-16,000 0-8,000
H
~ Basic cement properties: Chemical and physical characteristics; API classifications and geographical application; how to calculate slurry density, yield and cost
classes
J
.
0-8,000 12,000-16,000
As manufactured. 1.50 F per 100 teet.
Based
Available sulfate resistance Ordinary Moderate
-
Characteristics,availability
Common(construction), widely avail. Special (construction), avail. California, Canada Ord., mod.,high High early strength, fine grind, widely avail. Mod.,high Coarse grind, retarded, not avail. North America Same as D Mod.,high Same as D Mod.,high Basiccement, no chemicalretarder, avail. Mod.,high West. U.S. Moderate Basic cement, coarse grind no chemical retarder, GulfCoast &Mid-Continent Resistsstrength retrogression,min. temp. High 2300 F on normal size cement job in well with geothermal gradient of
The nine classes cover applications to depths of 16,000 feet (4,800 m), as manufactured, and a wide variety of depth and temperature/pressure conditions with addition of accelerators or retarders. Because sulfate salts have low solubility at temperatures above 140° F, sulfate resistance is not normally a consideration at that temperature or higher. Some 40 manufacturers around the world are authorWORLD OIL
1977
J: I(!) Z W a:: Ien w > c;; en w a:: a. ::;; o
Geologists and Uni~ed States Geological Survey has been published in two map sets "Subsurface Temperature Map of North America" and "The Geothermal-Gradient Map of North America." These maps are available through the Branch of Distribution, U.S. Geological Survey, 1200 South Eads St., Arlington, Va. 22202 (or same office, Box 25286, Federal Center, Denver, Colo. 80225) at a price of $4 per set. Service companies can also supply such data.
8,000
, 4,000
()
NOT PUMPABLE 30
PUMPABLE
46.~
I 50
WATER CONTENT, %
Water is added to cement to make the slurry pumpable, and provide for hydration (the chemical reaction). Although only 25% water by weight of cement (Fig. 22) may be needed for hydration (a slurry density of about 18.3 ppg), normal water content is higher to provide for pumpability, as shown below:
Neat cement slurries 22-Compressive
strength of cement is reduced nearly in proportion to amount of water in slurry. Approximate points for water required for hydration, "minimum" water and "maximum" water are also indicated..' Fig.
ized to use the API monogram for one or more classes of cement; still, only a few classes are available in a given area. However, two "basic" cement classes can be modified with accelerators or retarders to cover a wide variety of pressure/temperature conditions-Class G (available in Colorado, California and Alaska) and Class H (available in Mid-Continent and Gulf Coast). Depth ratings of cement are based on lab determinations of thickening time and minimum compressive strength development, in which samples are subjected to simulated temperature/pressure behavior representative of a large percentage of actual jobs.61 Thickening time is the time required to reach the approximate upper limit of pumpable consistency. Minimum thickening time specifications (and maximum for classes G and H) are based on pumping times from field data. Minimum compressive strengths are specified after 8 and/or 24-hour curing times for samples subjected to pressure (3,000 psi except for 1,000-foot and 2,000-foot simulations) and temperature (based on a geothermal gradient of 1.5° F per 100 feet). Since actual geothermal temperature gradient, bottom hole circulating temperature and time requirement may differ from those used in the lab to establish depth ratings, such ratings will not always be applicable. For instance, geothermal temperature gradients range from about 0.8 to 2.4° F per 100 feet in various parts of the southeast United States. Where the gradient is low, depth rating might be extended; conversely, depth rating might have to be reduced where the gradient is high. A recent (1976) compilation of subsurface temperature data by the American Association of Petroleum WORLD OIL
1977
Percent water
Class
I
A. . . ..... ........ .. B............ ........ C................. .... D..... . .. .. '" .... E....... .. ... ... F............. ... G..... .. H. ... ... J. ...
46 46 56 38 38 38 44 38 38-43.5
per sack Gals.water
Slurry den., ppg*
Slurry yld., ft.'/sk*
5.19 5.19 6.32 4.28 4.28 4.28 4.96 4.28 .28-4.91
15.6 15.6 14.8 16.4 16.4 16.4 15.8 16.4 16.0-15.4
1.17 1.17 1.32 1.05 1.05 1.05 1.14 1.05 1.09-1.17
* Based on absolute vol. per sack cement equal 3.59 gals.
The normal water content differs for various classes according to fineness of grind. Excess water should be avoided to prevent cement-water stratification. API requires that Class G and H slurries have less than 1.4% top settling (free water) as measured in a 250 ml graduate in two hours. Care should be taken to add the proper amount of water for the cement to be used. For example, Class H is sometimes inadvertently handled like Class A, and the resulting mix has reduced strength, retarded thickening time and excessive free water. Free water content is usually higher at increased temperature due to thinning, and lab tests at elevated temperature are sometimes required. Free water can be minimized by: Limiting the amount of mix water, adding bentonite in small quantities or selecting and controlling quantity of other slurry additives. How to calculate yield, cost. To estimate job cost, price per sack is not as important as cost per cubic foot of slurry because the latter varies with yield due to different water contents. Slurry density, yield and cost can be calculated, given specific gravity, bulk weight and water required by the cement-or additive-and cost of the material, as follows: Given: . One sack (one cubic foot) of Class A cement weighs 94 pounds . Cement cost is $3.75 per sack
23
.
5.19 gallons of water required per sack . Specific gravity of water is 1.0, density is 8.34 ppg . Specific gravity of cement is 3.15, absolute density is 3.15 X 8.34 ppg
= 26.21
ppg, and
. One cubic foot equals 7.48 gallons. Then:
. Absolutevolume of cement = 94/26.21 = 3.59 gallons · Weight of water per sack = 5.19 X 8.34 = 43.28 pounds . Absolutevolumeof water = 5.19 gallons. And:
. Slurry density (3.59 + 5.19)
=
Weight/volume
= 15.6
ppg
=
(94
+ 43.28)
/
. Yield = gals. per sack/gals. per ft.' = 8.78/7.48 = 1.17 ft.' per sack . Slurry cost = $3.75 per sack/I. I? ft.' per sack = $3.21 per it.' Most slurry additives are expressed as percent by weight of cement. One exception is salt which is expressed as percent by weight of fresh water. When additives such as bentonite are used in the mixture, this calculating method must be expanded. Densities and water requirements of most additives are included in the accompanying table. Service companies can also provide such information to customers, with density and yield already calculated for most mixtures. Another source of information aspects of cement and additives Cementing, by Dwight Smith.62
concerning the chemical is the SPE Monograph,
CEMENT ADDITIVES Almost all cement used in oil and gas wells is Portland cement. However, "neat" cement is seldom used throughout a job as various additions are usually made to modify the following properties of either slurry or set cement: Set cement
Slurry Thickening Time Density (yield) Friction during pumping Fluid loss (filtrate) Lost circulation resistance
Compressive strength Strength retrogression Cement strength downhole Expansion
A listing of selected additives available from major U.S. service companies is shown in the accompanying table. And the following discussions explain functions of these additives in modifying cement composition. Mud contamination also acts on the slurry to affect some or all of the above properties; these effects will be discussed in a later article.
Thickening time. may be varied using accelerators or retarders. The most common accelerators are: Calcium chloride, sodium silicate, sodium chloride (low concentrations), seawater, gypsum and ammonium chloride. Additives that retard are: Calcium lignosulfonate, organic blends, carboxy methyl hydroxy ethyl cellulose (CMHEC), borax, sodium chloride (high concentrations) and most fluid loss agents. Thickening time is a function of both temperature and pressure, Fig. 23.63 Thickening time can also be shortened by interruption of pumping (loss of agitation). And API tests can be done in this manner to simulate actual interruptions during squeezing (tentative). Thus, thickening time of a slurry must be esta:blished for realistic conditions to ensure adequate pumping time for slurry placement. Avoid excessive thickening time to prevent: Delays in resuming drilling operations, settling and separation of cement slurry components, formation of free water pockets, loss of hydrostatic head and gas cutting. Increased water lengthens thickening time of unretarded cement (Classe A, C, G, H). However, with retarded cements (Classes D, E, F) increased water or solids may shorten thickening times by reducing the concentration of retarder.64 Thickening time can be measured using pressurized consistometers. API has developed schedules, for pressure/ temperature increases versus time, that simulate cement placement conditions for different types of cementing operations such as squeeze cementing (also plug back), liner cementing (tentative), casing cementing and alternate hesitation squeeze cementing (tentative). Thickening time tests can also be tailored to individual well condi-
----
- -----------
10
5,' API CLASS AS NOTED
8
CLASS A
4 00 a: J: W :2 i= Q :E I-
3
2
-
14QOF
2
180°F
o 40
60
80
140
160
180
o
I 2
I 3
4
5
Fig. 23-Effect of temperature and pressure on thickening time of Portland cement. At atmospheric pressure, left, thickening time is reduced by high temperature. At constant temperature, right, thickening time is reduced by pressure (after Bearden)..'
24
WORLD OIL
1977
Selective products of major U.S. service companies
Accelerator Calcium chloride. . . . . . . . . . . . . . . . . . . .
Salll-6%.............. ............ NaCl,CaCI, mixture....... ...... .... . CH.CI, CaCI, blend. . .. . . .. . .. . .. .. .
Sodiumsilicate. .. . .. .. . ... ........ Retarder Calcium lignosulfonate...
. .. ..... .. ....
Calc. ligno.(Kembreak).......... .... .. Hightemp. blend. . . . . .. . . .. . . . . . . . . . . lignin-liquid. . . .. .. .. .. .. .. .. .. .. .. .. CMHEC(carboxymethyl hydroxy ethyl cellulose). . .. . .. . .. ... .. .. .. Salt (saturated)......... ... .. . . . .. .. Borax............................. . Thixotropiccml. retarder. . . . . . . . . _. . Extender Bentonite........................... . Diatomaceousearth. . . . . . . . . . . . . . . . . POllolan: Fly ash. . . . .. .. .. .. .. . .. .. . . .. . .. Natural pOl. (S. Tex.). . . . . . . . . . . . . Natural poz.(Calit.)..... .. .. .. .. ..
Tradename
Bulk density, Ibs./ft3
Water required, gal./sk
1.75-1.96 2.16-2.17 2.00 esl. 2.00 esl. 2.62
50 70-71 50 esl. 50 esl. 60
None None None None None
A8 DiacelA
1.5-1.56 1.23-1.30 1.22 1.26
35 30 23 .-
None None None None
R-5 R-5 Rll, R14-l R-IOl
1.36 2.16-2.17 1.73 5.47
29 70-71 65 ..
o (up to 0.7%)
2.65 2.10
60 16.7
1.3 (2% gel) 8.2 (cu. II.) 10%-5.0gal
2.46 ..
74 ..
3.6 .. ..
Specific gravity
Product
.. .. ..
Dewell
OJ-Hughes A7, A7-l, A6 A-5
SI D44 D43
Dresser
CaCI, Sail
il57
MA-2 DiacelA
HA-5 DiacelA
DI3
HR-4 HR-7
D81
MlR-3 MlR-I MHR-8 MlR-l
HR-6l
WR-2 WR-I WR-6 WR-ll
R6 (Diacell Wl) A-5 Borax ..
D8, lWl D44 D93 D74
MFlR-7 Salt MHR-9 ..
Diacell Wl Salt Borax ..
Diacell Wl Salt Borax WR-IO
BJ Gel DiacelD
Gel D20 D56
M-Gel DiacelD
Gel DiacelD
Bentonite DiacelD
DiamlxF (74#)
035 (74#)
Magco POI A Magco POI N
DiamixA (47#) ..
ilin (47#) D48(60#) litepoz 300
..
POlmixA (74#) .. ..
D79
D49, Tl W, Dl W
Eeonoblend Trinity ll. WI. Thrilly mix
POlmentA (74# ) .. .. ..
Hallib.light Trinity ll. WI. Econolite
TLWi TXI Thrlty liteLt. WI.
Sand Barite HiDense3
Sand Barite Hematite
D28, D99, D100
60 87.0 75 ..
10.9 (max.) 7.66 (max.) 6-6.8 (2% sil.)
Trinity ll. WI. lodense
2.63 4.25 4.93-5.02
100 135 165-193
0 2.4 0-0.36
Frac sand 20/40 W-l W-5
Sand D31 D76
MS-3 Mcobar M -2
4.45
150
1.36 1.36 1.22 1.31
29 37-40 40
None None None
1.07 1.30
50 50
2.0 (50 Ibs.) 2.0 (50 Ibs.)
Walnutshells. . . . . . . . . . . . . . . . . . . . . . . Perlite expanded.. . . . . . . . . . . . . . . . . . . Perlite semi. expanded. . . . . . . . . . . . . .
1.28 2.40 2.40
50 8 43
0 4.0 (cu. II.) 6.0 (cu. fl.)
HIi::r;:::.t.re................... . Silicasand. . . . . . . _. . .. . . . . . . . . . . . . . Dispersant
2.63 2.63
70 100
Organic.. . . . . . . . .. . . . . . . .. . . . . . . . . .
1.30-1.63 1.18
Expanding cemen!. ... . . . . . . . . . . . . . . .
3.15 ..
Hematite (iron oxide). . . . . . . . . . . . . . .
Ilmenite. . . . .. . . . . . . .. . . .. . . . . . . . . . Fluid loss additive H............................ CEMAD-I(Amer.Cyananid).......... Organicpolymers................... OrganicpOIr,mer blend.... .. ... . _ ... Lost clrculat on material Gilsonite................ _.......... Crushedcoal (Kolite)................ Cellophane..
. .... .. ... .. ..... .. ... .
liquid.. .. .. .. .. .. . .. .. . .. .. . . .. . .. Special materials
Defoamers(Powder,liq., other)... _ .. Gelagent blend (Slo Flo).......
...
..
Plaster paris (Gygsumcement). . . _. . . :r:xu.t . 'n:: : : : : : : : : : : : : : Aluminate(CimentFondu,lumnite)... MudKiI(lo temp. and hi temp.)... . . . Nylonfibres... .. .. .. .. . .. .. . . . . .. . . Dieseloil cement (additive). . . . . . . . . . Prefiush-thick.................. _... Preflush-thin................... _... Oilmud spacer. . .. . . . . . . . . . . . . . . . . .
2:66
2.89
2.26 2.70
2.90esl. 1.10 3.20
1:23 0.90-1.00 I.Ui'esl. 1.10esl.
gal/IOO Ibs.
Western
CaCI, Salt
2.71 2.40
Fly ash (NewOrleans, Houston)....... Cement Pouolan and Bentonite.. . . . . . Calcinedshale-cemenl.. . . . . . .. . . . . . . Anhydroussodium meta-silicate. . . . . . Weight material Ottawa sand. . . . . . . . . . . . . . . . . . . . . . . . Barite............................ .
Halllburten
CaCI, Salt .. illacel A
HR-12, HR-20
..
D18
MW-I
..
Ilmenite
R-6
D8
MFlR-7
D-19
il59 D60
MFl-5 MFl-4
DiaceI l Wl CEMAD-I Halad 14
Diacell Wl CEMAD-I CF-I, CF-2,CF-6 CF-3(ultra low)
Gilsonite
Gilsonite
Gilsonite
Cello-Flake Tuf-Plug BJ Perlite Oil Patch Nine
D24 D42 D29 J51 072 ..
Cell-O-Seal Nut Plug
Cello-Seal Tuf-Plug
Perlites
FloceIe TUf-PIU Perlite ego Perlite Six
4.8 (100Ibs.) None
D-8 D-8C
D66 D30
MS-I MS-2
SSA-I SSA-2
SF 3 SF 4
40-43 ..
None None
D-31 D-31l
D65 D80
MCD-l
MCD-3, MCD-4
CFR-I,CFR-2 CFR-22L
TF-4 ..
94
6.3 ..
Chem Comp 0-6, D-6l, 0-21
Chem Comp D46,D47
ChemComp MFP-5,l
ChemComp AF-8,AF-l
75 75
4.8 4.0 0 4.5 None None None
Gyp-Seal
D71 D53,RFC Arcticset D-15 lumnite Mud KiII, 2 094 M54,F33
.. ..
ChemComp NF-P NF-I D-Air1,2 '
Hard Set I, 2 .. ..
Swcer 1000 C 7, CWlOO OBMSpacer
MMW-l MCS-2,MCS-3
90
.. .. ..
None
o (up to 0.7%)
.. ..
0-7
0-5 lumnite Firm Set I, 2 VisqueezMK-II MudSweep MudClean Unimul
MCl-2
Halad 9, 22A
Cal-Seal Permafrost II latex lA-2 lum. C.F. fda.
g2--
Ii 2
DOC-IO
MCA, Mud Flush
SAM-4
..
VCT Thixad CLX-I lum., C.F. .. Excello-Gel WMW-I APS-I, APS-2
Basic cements' (Class A, B, C, D, G, H): Specific gravity 3.15, bulk density 94 Ibs';sack (80 in Canada). See accompanying table for water requi remenl. Note: "None" means water required is not significant or is not intended to be used. " . ." means data or trade name is unknown, product may be available. This table is not a complete listing of available products. Please check with local service companies.
tions by service companies, if the published API schedules are not applicable. Note: These measurements are made in metal vessels which prevent any fluid loss. Thickening time values determined are therefore higher than they might be opposite a permeable zone, after partial dehydration. Slurry density may be reduced with extenders such as bentonite, pozzolan, diatomaceous earth and anhydrous sodium meta-silicate. Gilsonite and crushed coal also reduce density. And special calcined shale--cement (such as Trinity Lite-Wate or Texas Industries Light Weight) are used for this purpose. Low density is frequently desired, to decrease likelihood of breaking-down the formation and causing lost circulation. In addition, such slurries cost less per cubic foot, as yield per sack is increased. Density decrease results in large part from increased water content. Extenders permit water addition without separation. However, cement strength is reduced approximately in proportion to water content increase, Fig. 22. WORLD OIL
1977
However, as was discussed in Part 1, high cement strength is not always required. Bentonite has for years been the most commonly used additive for "filler" type cement.65 In addition to its effect on density, yield and cost, bentonite increases viscosity and gel strength, which reduces settling of high density particles (weight material, cement) or floating of low density particles (Perlites, pozzolan, gilsonite, crushed coal). Bentonite al:;o reduces API fluid loss. However, cements containing bentonite are more permeable and have lowered sulfate resistance. Pozzolans increase slurry viscosity and provide low permeability. Sodium meta-silicate provides a very lowdensity slurry with early compressive strength; this material and calcined shale-cement are becoming popular, particularly offshore. The latter is a special cement, not an extender, as mentioned earlier. Light-weight cements are listed in the accompanying table which separates slurry compositions providing more 25
:2
Il. (XI
25
~
1% ORGANICDISP. ADDED
c::::::J WITHOUT DISPERSANT
ui I-
«a: 3i:
o..J U.
..J « o i=
a: o
o
CLASS E
CLASS A
50/50 POZ
dispersants reduce yield point to allow turbulent
Fig. 24-How
flow at reduced pump rates in a 5V2-inch casing by 7\18-inch wellbore annulus.""
than, and less than, 500 psi compressive strength.66 The lowest-weight slurries providing more than 500 psi compressive strength are Class C cement with gel, and Class C cement with silicate.
Common light weight cements Extender,
1-.-.--.-.-.Gel
Type cement Gel Class H .....
Class C" . .. . . . . . . . . .
Prehydrated
gel.
. . .. .
Pozzolan and lIy ash 50/50. . .
Salt
I
H . . . . .
ClassC... .. .. . .. .. Dlacel D... ... .. .. ..
I
Dlacel
D
I
I
Above
Below
500psi SOD psi 14.1 13.1
'l,i.2 13.7 12.8
'l'2j 12.1 11.8 10.7
14.1
'i.o' 2.0 3.0
6f 6f 6f 6f
13.3 12.8 12.4
'1.1.2 12.5
....
74
....
83 104 104
I
I
13.7 12.8
I
I
13.6
I
'13'.2
. io' 20 30 40
.
13.1 12.4 12.0 12.4 11.7 11.0
Perc ent by weight water
.. Trin ity Lite-Wate data. Similar cement available from Texas Industries. f 65/ 35 cement and Pozmix A, % gel based on combined
weight.
Density may be increased with weight material such as sand, barite, hematite or ilmenite, and/or salt dissolved in the mix water, as shown in the following table:66
Weight material for cement "'aterlal --
Jttawa sand....... 3arite.. . ... .. . .. .. :oarse barite. . . . . . Hematite.. .. .... Ilmenite..... . Dispersant..... ... Salt..... ......
26
Speci fie gravity 2.63 4.25 4.00 5.02 4.45 .... ...
-
Grind (mesh)
Max. density, ppg
20-100 325 16-80 40-200 30-200 ...... ......
18 19 20 20 20 17.5 18
-
Extra water needed None 20% None 2% None None . ..
Elf. on compo strength
-
None Reduce None None None Increase Reduce
Friction reduction. Dispersants can also be used to reduce the yield point (consistency index) of the slurry, which reduces friction and allows turbulence to occur at reduced pump rates, Fig. 24. Common dispersants are: Alkyl aryl sulfona~e, polyphosphate, lignosulfonate, salt and organic acid. Turbulent flow additives tend to cause settling and excessive free water. These effects should be tested in the lab prior to field use.
'13".i 12.5
65 85 95 115
Pozzolan and bentonitef
compo strength:
4 8 12 16 4 8 12 1.5. 2.0. 2.5. 3.0. 3.5. 4.0. 4.5.
Calcined shalecement.. . . .
Class
Sodium metaI sll. Water
-1-1-1--1-1-
2 6 10 18
Silicate......
Density, ppg, for
% by wt. cement
A density of 22 ppg can be obtained with hematite or ilmenite plus friction reducing additives. Fine barite (325 mesh grind used in mud) requires a large amount of water, which reduces compressive strength and retards thickening time, and therefore is rarely used. A slurry weighted with solids must have viscosity and gel strength needed to carry and suspend high specific gravity solids. And it should be noted that some additives tend to significantly thin or thicken a slurry (fluid loss agents, retarders, water content)_ Pretesting of such high density slurries should include density, thickening time, compressive strength, settling, free water and viscosity measurements. High density (up to 17.5 ppg) may be obtained by adding dispersant to the slurry to provide pumpability at lower than normal water/cement ratios. This approach is most expensive, but results in highest compressive strength. Cement densified in this manner also may need an additive to reduce filtrate loss because further reduction in water content may make the slurry unpumpable. Also, densification tends to accelerate curing time.
Elf. on pumping time
-
None Reduce None None None Increase Varies
Fluid 1055 (filtrate). Addition of fluid loss agents has important application in: P reven ting gas leakage, in squeeze cementing and, occasionally, to maintain pumpability in primary casing and liner cement jobs. Fluid loss additives may also reduce likelihood of differential pressure sticking where stuck pipe has been associated with mud cake removal. Fluid loss additives might be considered when there is little or no mud cake on the borehole wall-for example, when drilling with water. In normal primary cementing, high fluid loss cement does not dehyrate significantly in permeable zones because filtration is controlled by the mud cake. The API fluid loss test on cement is conducted at 100 or 1,000 psi differential pressure through a 325 mesh screen. 1,000 psi is used when the slurry has been elevated in temperature and pressure in a consistometer in accordance with one of the API simulation schedules. Testing conditions .need to be identified for the true meaning of the data to be known. In addition, many 100 psi tests are mistakenly run on No. 50 Whatman paper instead of 325 mesh screen. Water dehydrates almost instantly from a neat cement tested in the above manner. The 30 minute fluid loss (100 psi) of neat Class A cement is about 1,000 ml. Early in 1960, significant progress was made in developing cement additives that lower fluid loss with a high molecular weight, synthetic polymer.68 Such additives may provide fluid loss in a low range. These additives usually are affected by temperature, Fig. 25. Generally, thickening time is retarded and, at low temperature, this WORLD OIL
1977
retardation may have to be offset by accelerators. Concentration and/or combination with other fluid loss materials may have to be adjusted accordingly. For most cement squeezing and gas leakage applications, 50-150 ml fluid loss cements (30 minutes at 1,000 psi) are used. Bentonite and CMHEC are also used to reduce filtrate loss. Fluid loss vs. gas leakage. Under certain conditions associated with gas sand cementing, formation gas can move through the pipe/borehole annulus as the cement sets. This leakage can pressure-up the annuli between casing strings or between pipe and formation; it can cause failure of liner laps, even blowout of surface pipe.69 Such gas entry into the cement column occurs70 when a column-supporting seal forms in the slurry in the annulus above the gas zone, and water from the slurry seeps through the mud cake into permeable formations, lowering column weight. The effective hydrostatic pressure may be reduced by this mechanism to less than reservoir gas pressure. Another mechanism for gas entry would be for the hydrostatic pressure of mud, preflushes and cementbefore any water loss-to be less than reservoir pressure, but this can, of course, be avoided by proper design. The annular seal may be caused by: Bridging from cement dehydration; fast setting of a portion of the cement column; gelation (or a significant viscosity increase) of the column from slurry chemical reactions; and/or bridging due to caving or sloughing formations, or removed mud cake/cutting debris. A most important aspect of gas leakage prevention is reduction of cement fluid (filtrate) loss. In addition, steps may be taken to ensure that the cement slurry opposite the gas sand will set up faster than other slurry in the annulus. Allowance may have to be made for the possibility that after lengthy circulation, cement slurry temperature may be highest some distance off bottom.71 Fluid loss in squeeze cementing. Control of cement fluid (filtrate) loss can be important in this application. When pressure is applied, water or fluid will be forced from the slurry if it is in contact with a permeable surface free of mud cake. The solid particles become compacted and slurry density increases. If the cement contains no fluid loss control agents, the cement particles may eventually bridge and prevent further slurry move ment. This concept was demonstrated in a core taken through cement remaining in the borehole following the squeeze of a perforated interval.72 Density measurements showed signficant slurry dehydration across and somew ha t above the upper portion of the perforations, Fig. 26. There was no cement across lower perforations-although squeeze pressure exceeded fracture pressure-as the dehydrated neat API Class E cement had bridged-off the casing. A low filtrate loss formulation may have prevented such dehydration and bridging. Highly successful results are obtained when squeeze operations are conducted with: Low fluid loss cement, clean completion fluids (such as salt water) and relatively WORLD OIL
1977
220
II.. °
200
a.: :::i: w 180 Iw ...J 0 J: :::i: 160 0 lI0 CD 140
"\ 0°/0 ~O~ i~;~"'''''''''' ........................... ...,..""
",......
",.."..".".". .,.,..",...",.,.,
120 30
20
40
50
FLUID LOSS (ML/30 MIN., 1,000 PSI)
Fig. 25-High molecular weight, synthetic polymer greatly reduces fluid loss. Example shows effect on API Class E cement (after Stout and Wohl).'"
TOP OF
.-.1
"I ~ u. ~ I0. W o ..J
CORE
CEMENT TOP OF
.a c'" 'C c~ ::'C [J:~ 0
c,
-- -
..J W
;:
" I..
9,760 9,770
-------------17
--18
19
CEMENT DENSITY, PPG
20
w-
. '.' C :..d'.~.
~
g n
y
g
n-
PERFS. BOTTOM
OF CORE
BOTTOM OF CEMENT BOTTOM
.J>I- OF PERFS.
Fig. 26-Results of a core test through cement following an attempted perforation squeeze indicates slurry dehydrated at the top of the perforations. There was no cement in the bottom of the perforated interval (after Beach, et al)."
low final squeeze pressures. Squeeze techniques plications will be discussed in a later article.
and ap-
Lost circulation. Drilling fluids or slurries are usually lost to either natural or induced formation fractures. These fluids may also be lost through highly permeable formations-starting at about 5 darcies for drilling fluid with a maximum particle size of 0.002-inch (300 mesh). Cement with its larger particle size (neat cement has 2.6-18% particles larger than 200 mesh) is less susceptible to loss in permeable formations. The best time to treat the formation to reduce such fracture or formation permeability-and thus increase the downhole pressure at which circulation is lost-is during drilling when high concentrations of bridging materials and various types of plugs (pills) may be utilized.73 During primary cementing, concentrations of such materials must be more carefully controlled to avoid bridging the casing or liner/borehole annulus, or plugging of downhole equipment such as bottom wiper plugs, small diameter storage tools and float equipment. The subject of lost circulation during drilling is discussed briefly below, in relation to cement formulations 27
----
---
polymer-can be effective when water bearing sands are present. In application, these materials are pumpable until they set up or expand upon contact with water. 4. Gypsum cement. A quick setting hard cement for use at shallow depths, it differs from construction gypsum in that it is semi-hydrated to control pumping time. Soluble salts in mixing water can greatly accelerate thickening time. Therefore, pumping time should be checked before the job, considering the water on location. Gypsum is considered a temporary plugginl{ material as it is water soluble after it sets up. 5. Other cementicious, high-water-loss, high-solids slurries such as Diaseal M and barite. plugs. The latter can be formulated to 21 ppg. Bridging materials can be used in most of the above compositions when loss is severe.
TYPICAL L.C.M.
.18 ci w .16:
...J
« w 00 .14 W a:
.12
() « a:
.1
I0
.08
...J 00
FIBROUS
PROPERTIES OF SET CEMENT Cement compressive strength increases as a function of temperature, pressure and time to an ultimate value which depends on cement composition. Compressive strength measurements are obtained on the basis of 11 API pressure/temperature/time schedules, for depths from 1,000-20,000 feet. A temperature gradient of 1.5° F
.06 w C) a: « ...J
o
16 CONCEN1:RATION, LBSJBBL.
20
10,000 _ "
Fig. 27-Granular lost circulation material was most effective in sealing simulated downhole fractures in lab tests (after Howard and Scott)."
9,000 1-
;'
K}, ,
Types of lost circulation additives available for cement are blocky-granular materials (walnut shells, gilsonite, crushed coal, Perlite-expanded and Perlite-semi expanded) which form bridges; and lamellated materials (cellophane flakes) which form flake type mats. Fibrous materials (such as nylon fibers) are effective in drilling fluid for sealing large openings but are not normally used in cement because of the tendency to plug surface and downhole cementing equipment. Also, most other fibrous materials contain organic chemicals that can seriously retard cement thickening time. On the basis of lab work by Howard and Scott,74 granular material was found best for bridging fractures (slots), Fig. 27. Cement plug formulations may be selected on the basis of these characteristics: Quick-gelling, low density (high yield), rapid set, fluid loss (filtrate), and cement plug drillout rate. The product also should be easy to handle and "weevil-proof."73 The following compositions are used as cement plugs (pills) : 1. Thixotropic cements. Blends of Portland cement and gypsum, these cements are thin while beinl{ pumped, but develop gel strength quickly when pumping stops.'"' '" Field experience has shown that quick-gelling cements stay closer to the wellbore (within surrounding fractures, etc.) in lost circulation applications. The cement also has high filtrate loss. Note: Fluid (filtrate) loss is important when dealing with mud or slurry loss to fractured, permeable formations. Assuming that frac pressure exceeds reservoir pressure, high filtrate loss cements (such as untreated thixotropic or neat) can dehydrate and bridge within such fractures, thus blocking further fluid loss. 2. Neat or low density cements. As discussed above, neat and thixotropic cements have high filtrate loss. However, low density cements mayor may not have high filtrate loss. 3. Mixtures with diesel-oil. Various compositions-diesel and bentonite; diesel, bentonite and cement; or diesel, bentonite and
28
7,000 (i5 :i' IC) z w a: I00 0..: ::2 0 ()
9,000
,{" , \ \\
I
a..
*72HR
I\,x
8,000 II-
and additives that might be considered for such applications. However, a complete review of the lost circulation problem during drilling is beyond the scope of this series. Control of lost circulation during primary cementing will be discussed in greater detail in a later article.
-..--
- -
-
r
PSI
1,000 PSI CLASSC
\
6,000
CEMENT
5,000 4,000
/'I
3,000
2,000 1,000
o 180 200
220
240
260
280
300
320
340
CURING TEMP. of
B
10,0001 (i5 a..
"nnnL
:i' IC) Z W a: I00 0..:
::2 0 0 a: :J:
,uuu
/
A
J/
ASTM TYPE 1
n/
C
V
oqN
AT 200°F
0 ATMOS
,,".,
,,
6,600
4,000
2,000
CURING PRESS.,
. -- -
---
PSI
'8:000
- - -.
..
Fig. 28-Effect
of curing pressure and temperature on compressive strength. At constant temperature, bottom, 24-hour strength changes little above 3,000 psi. Slow set, Class C cement, top, shows significant strength retrogression as curing temperature increases ('curing pressures)."
WORLD OIL
1977
per 100 feet is provided-for in each schedule. The pressure is 3,000 psi for all schedules except the two shallowest (1,000 and 2,000 feet) for which it is less.
_0 c::::J
Strength retrogression. Four variables-composition, temperature, pressure and time-affect compressive strength.77 However, at high temperature, cement compositions may retrogress (lose strength) after reaching a high value and never attain the strength reached at lower curing temperature; Fig. 28, top, illustrates one severe example. This strength retrogression is accompanied by increased cement permeability, i.e. a neat retarded cement with 0.02+ md permeability at 2900 F after three days may have 8+ md at 3200 F after seven days.78 Retarded cement for high temperature application, and high water content cement, seem particularly subject to strength retrogression (Fig. 28). For cement types used in deep and/or hot wells the phenomenon begins at around 2600 F, and becomes severe at 2900 F. Generally complete strengt!1 retrogression has taken place within seven days.78 Although remaining compressive strength may be adequate for many applications, addition of flour
to the
slurry
provides
a way !o maintain
strength.79
II
~
30
:~I
PERCENT
20
The reason why API tests are run at 3,000 psi or less is that compressive strength changes very little above that pres'Sure level, Fig: 28, bottom. However, at high temperatures (about 250-3000 F) pressure effect may be more significant than those of Fig. 28. Tentativp data indicates, at least, that actual well pressure should be more closely simulated. Recommended curing periods are 8, 12, 18, 24, 36, 48 and 72 hours, depending on job requirements (such as waiting-on-cement time or strength retrogression). Usually, com pres'Si ve strength is very close to ultimate within three days. Early strength is increased with calcium chloride, 'Sodium chloride, ammonium chloride, "minimum" water and heat. Early strength is decreased with lignosulfonate, CMHEC and "maximum" water. Compressive strength inf orma tion is available through service companies.
silica
-I
SILICA
3 1 7 3 230'F 260'F 290"F CURINGTIME(DAYS)I CURINGTEMPERATURE
Fig. 29-Silica flour inhibits strength retrogression at high temperatures as indicated for Class E cement. For example, 20% silica increases the 2,000 psi, 7-day compressive strength of neat cement to 12,000 psi, at 2900 F (after Ostroot).'. Silica flour in high percentages inhibits strength retrogression and produces compressive strength far in excess of neat cement, Fig. 29.79 Silica flour also reduces permeability of set cement; for instance, its addition to cement cured at 3500 F reduces permeability to less than 0.001 md. Maximum strength cccurs at 300-4000F when 30-50 parts of silica flour are added to 100 parts of cement.80 Usually 35% silica flour is used. Silica sand ground to 200 mesh reacts with cement in the same way as fine ground 325 mesh silica flour. Silica sand is used when high density is desired and silica flour when low density is adequate. Compositions containing silica sand or flour can be retarded effectively for high temperature wells.79 Class J cement does not require silica flour and can be used to about 16,000 feet without retarder-this class should not be used at less than 2300 F. Most crushed
nonreactive additives (salt, weight materials, coal, mica and other bulking agents) can be admixed with a silica stabilized cement without adversely affecting temperature stability.80 Bentonites, diatomaceous earth and expanded perlite should not be added to Portland cement for use above about 2500 F in concen-
---I
50
I I
I
(j) 40 0.. 0 0 q 'X I(!J Z W a: }j) w
20
I-
« 5 ;:!
10
5
- --Fig.30-Under Handin).81 WORLD OIL
10
-
15
0
confining pressure, ultimate strength of cement, left, is similar to that of typical
1977
10
EFFECTIVE CONFINING PRESSURE, 1,000 PSI
reservoir rocks, right (after
29
trations of 5-15% without adding about 20% extra silica. Natural pozzolans and fly ashes produce a strong material with silica stabilized cements up to 450° F. At a temperature of 600° F, fly ash and-to a lesser degreenatural pozzolans, cause cement to weaken and become more permeable.80
Salt cement is now used fairly extensively; some important characteristics of salt cement are shown in Fig. 32 and the accompanying table.66, 86,87,88
.
Characteristics .
Strength at downhole conditions. Handin conducted triaxial compression tests on various cement samples with independently applied external confining pressures and internal pore pressure such as encountered downhole.81 These tests show that strength increases, Fig. 30, and is more or less comparable to rock for similar conditions. Large variations in the standard compressive strength, as measured at zero confining pressure, tend to disappear under load; and oil well cements become very ductile, even under low confining pressures. However, for rapidly applied strain associated with gun perforating, ductility might be small. Cement can be highly compactible under confining loads, Fig. 31. Bulk volume reduction (of lab 'Samples) of 30% or more are attainable for some formulations. Neat cement shows least compactability. Expansion. Saturated salt cement, Pozzolan cement, Gypsum-Portland blends and several other formulations, some proprietary, expand during setting.82-85 Suggested as a benefit of this expansion, is elimination of the microannulus at the cement/casing interface. Cement expansion may increase thickness of a cement sheath by a few thousands of an inch. However, cement expansion and/or contraction would appear to be of minor importance, relative to the magnitude of other downhole effects such as: Inadequate mud displacement; mud cake thickness; borehole elastic/plastic deformation, and cement loading conditions, ductility and compactability. SPECIAL CEMENTS Unique cements and additives are available for nonconventional or extreme service applications such as high temperatures found in geothermal wells and other thermal projects, and low temperatures in Arctic permafrost. 30
?J?
2
u.i C) z
«J: 20 o w :2 :::J ...J o > ~ 10 ...J :::J
1 CLASS A, 100% DIAMIX A, 30% BENTONITE, 7.5% NASILICATE 2 INcaR, 8% GEL 3 CLASS A, 40% DlACEL D, 4.0% CAC" 4 CLASS A, MODIFIED 12% GEL 5 CLASS A, NEAT (SAMPLES CURED AT 3,000 PSI, 200°F EXCEPT 1,3 AT 110°F)
7,500 PSI EFF. CONFINING PRESS.
IJJ
o
. 2,000
4,000
6,000
8,000
COMPRESSIVE STRENGTH, PSI
Fig. 31-Compactibility of cement pressures. Bulk volume reduction is cement. At higher confining loads, compositions had over 30% volume
30
samples under confining significant except for neat 15,000 psi, certain other reduction (after Handin)..'
.
. . . .
of salt cement
Osmotic pressure will causewater from sand or shale to migrate to the saltcementcausing expansion which improves bond log..' Theoretically less disruptive to swelling and non-swelling clays, thereby minimizes cleavage, softening or sloughing of shale beds. Clay dispersion is minimized to aid well productivity should cement filtrate loss be significant. However, original mud cake normally prevents such filtrate loss. Salt is an accelerator in low concentrations and it retards at high concentrations, butthe effect is neutral throughout a broad range in between, Fig. 32. This tolerance can, in many cases, permit use of either fresh or seawater for mixing without affecting thickening time. Salt in small concentrations tends to increase early compressive strength, Fig. 32, but has little or no effect on ultimate strength. In high concentrations, it reduces early strength and can cut ultimate strength in half. Saturated cements minimize solution of formation salt sections. Can increase slurry weight by as much as 1.7 ppg.
. Inthe 3-5%
range, reduces turbulence-critical-flow velocity through dispersion and reduced viscous properties. At higher concentrations, over 18%, this effect is minor and typical dispersants may not be effective.
High temperature cements are now required for conditions which extend beyond the upper (in-situ combustion and some geothermal steam) effective limits of basic Portland cement. The upper limit for silica-Portland cements is around 700° F. This cement has application in deep, hot wells and many thermal recovery and geothermal wells.89 Calcium aluminate cement (Ciment Fondu or Lumnite) has been used in in-situ combustion wells where temperatures may reach 2,000° F. Calcium aluminate cement is manufactured from limestone and bauxite ores. Neat calcium aluminate cement has high heat of reaction and attains almost full compressive strength of some 12,000 psi in 24 hours. Admixes are fire brick, fly ash and silica flour. This cement is used as a mortar for fire boxes. In Arctic permafrost, permanently frozen subsurface formation, the surface temperature is so cold that underlying formations do not reach 32° F for several hundred feet. Permafrost is some 300 feet thick in the Mackenzie River Delta, about 2,000 feet on the North Slope. Cementing conductor pipe and surface pipe in permafrost presents a special problem because neat Portland cement will not set up and provide strength before it freezes.66 This problem is overcome in hard rock areas by heating the hole with warm drilling mud, then cementing with heated cement and mix water. The heating delays freezing of the cement until after it has set up. This method cannot be used through unconsolidated formations held together by ice because the hole will enlarge and create a void between cement and formation. Loose permafrost is cemented with either: Calcium aluminate cement/fly ash mixture or Gypsum-Portland cement blend. These mixtures will set up and provide more than 500 psi compressive strength in 24 hours. At present, the latter is in greater use. Gypsum-Portland cement blends90-92 are available through several service companies. These blends contain dispersant, retarder and enough salt to depress the freezing point to about 20° F. The slurries will set up at 15-20° F, have a low heat of hydration, no free water separation and they are stable under freeze-thaw cycling. The cement will develop about 500 psi compressive strength in 1-3 days and have 1,000-2,000 psi compressive strength in 7-28 days. The early strength comes from WORLD OIL
1977
the gypsum, later strength from the Portland cement. Cementing operations at Prudhoe Bay have been discussed in the literature.93 And API has established Arctic cementing testing procedures including freeze-thaw cycles.61,
94
Other special cements and additives available for nonconventional appliCations include: The Trinity Lite-Wate and Texas Industries Light Weight cements mentioned earlier, pozzolanic-lime cements, gypsum cement, latex cement, resin cement and cement containing nylon fibers for reinforcement.95 Information is available through the service companies. Radioactive tracers are sometimes used in cement for location purposes following primary cementing or squeezing. Also, additives such as defoamers and those which offset the retarding effect of mud contamination, are available.
Critical cement iobs for difficult wells should be planned in detail and the slurry must be carefully designed. Due to the large number of possible combinations of cement types and additives, variable operating conditions, variations in manufacture, inconsistent field water characteristics, etc., the only way to verify thickening time for critical jobs is to test the planned slurry at anticipated actual pressure/temperature conditions. The test mixture should use water from the location. And after preliminary design work is complete, the specially compounded cement should be blended at the bulk stations at least a day prior to use, to allow time for a sample to be lab tested. Coming next month: The displacement process during primary cementing: Flow theory; fluid behavior; what causes channeling; how to improve mud displacement.
ACKNOWLEDGMENT The authors wish to acknowledge the contribution of Mr. Kerr Godfrey of Atlantic Richfield Co. who provided valuable information and data included in this article. LITERATURE CITED .. Ludwig N. C., "Chemistry of Portland Cement Used in Oil Wells," Oil-Well Cementing Practices in the United States, API, 1959, pp. 27-37. .. "API Specification for Oil-Well Cements and Cement Additives," API Sp,ec lOA, 18th Edition, Jan. 1974. .. 'API Recommended Practice for Testing Oil-Well Cements and Cement Additives," API RP lOB, 19th Edition, Jan. 1974. .. Smith, D. K., "Cementing," SPE Monograj>h Series, Vol. 4, SPE of AlME, 6200 N. Expressway, Dallas, Texas 75206. "Bearden W. G., "Effect of Temperature and Pressure on Ph sical Properties of CemenU," Oil-Well Cementing Practices in the Unite 'J States, API, 1959, Pl'. 49-59. .. Anon., "Applied Engineered Cementing," Manual, Byron Jackson Inc., Vol. 1. .. Morgan, B. E. and Dumbould, G. K., "Recent Developments in the Use of Bentonite Cement," API Drilling and Production Practice, 1953, pp. 163-176. .. Godfrey, W. K., Atlantic Richfield Co., Persocnal communication, 1977. "McLean, R. H., Manry, C. W. and Whitaker, W. W., "Displacement Mechanic. in Primary Cementing," Journal of Petroleum Technology, Feb. 1967, 251-260. .8 Stout, C. M. and Wahl, W. W., "A New Organic Fluid-Loss-Control Additive for Oilwell Cements," Journal of Petroleum Technology, Sept. 1960. .. Stone, W. H. and Christian, W. W., "The Inability of Unset Cement to Control Formation Pre.sure," Paper SPE 4783, Presented at the AIME Symposium on Formation Damage Control, New Orleans, La., Feb. 7-8, 1974. 10Carter... G. and Slaglel K., "A Study of Completion Practices to Minimize Gas '-'Ommunication,' Paper SPE 3164, Presented at Central Plains Regional Meeting, Amarillo, Texas, Nov. 16-17, 1970. 71Holmes, C. S. and Swift, S. C., "Calculation of Circulating Mud Teml'eratures," Journal of Petroleum Technology, June 1970, Pl'. 670-674. "Beach, H. J., O'Brien, T. B. and Goins, Jr., W. C., "The Role of Filtration in Cement Squeezing," API Drilling and Production Practice, 19&1,pp. 27-35. "Messenger, J. U., "How to Combat Lost Circulation," Oil and Gas Journal, Three Part'Series, May 13, 20, 27, 1968. "Howard, G. C. and Scott, Jr., P. P., "An Analysis and The Control of Lost Circulation," Transactions of AIME. Vol. 192, 19.'H, Pl'. 171-182.
WORLD OIL
1977
7 :z: l6 e!) Z W a::....: 5 I-CI) Cl)Do '0 Doo
::2:0 0": U
a:: J: '
4
3V
CURING TEMP.
2
100 200 SALTCONC., 1,000 PPM
300
6 5
en a:: J: ui
4
::a:
i=
3
U :i: I-
2
CONSISTOMETER
DEPTHS
1 0
100
200
300
SALTCONC., 1,000 PPM
Fig. 32-Effect of sodium chloride (salt) on cement properties. Small concentrations shorten thickening time, bottom, and there is a broad range where the effect is minimal before salt retards set-up. Early compressive strength is increased by small salt concentrations, top. Data taken from tests of retarded oil well cement (after Ludwig)." "Spangle, L. B. and Calvert, D. G., "Improved Primary and Remedial Cementmg with Thixotropic Cement Systems," Paper SPE 3833, Presented at Rocky Mountain ReglOnal Meeting, Denver, Colo., April 10-12, 1972. "Clement, C'~A"A Scientific Approach to the Usage or Thixotropic Cements," Paper SPE bUll, Presented at the 51st Annual Fall Meeting, New Orleans, La., Oct. 3-6, 1976. 1TMid-Continent District Study Committee on Cementing Practices and Testing of Oil-WeII Cements, "Effects of High Pressures and Temperature on Strength of Oil-We II Cements," API Drilling and Production Practices, 1954, Pl'. 72-81. 18Carter, G. and Smith, D., "Properties of Cementing Com~ositions at Elevated Temperatures and Pressure," Transactions of AIME, Vol. 213, 1958, Pl'. 20..27. TOOstroot, G. W. and Walker, W. A., "Improved Compositions for Cementing Wells with Extreme Temperatures," Journal of Petroleum Technology, March 1961, pp. 277-284. so Eilers, L. H. and Root, R. L., "Long-Term Effects of High Temperature on Strength Retrogression of Cements," Paper SPE 5028, Presented at 49th Annual FaII Meeting, Houston, Oct. 6-9, 1974. 81Handin, J., "Strength of Oil WeII Cements at Downhole Pressure-Temperature Conditions," Journal of Petroleum Technology, Dec. 1965, pp. 341.347. .. Carter, L. G., Wag~oner, H. F. and George, C., "Expanding. Cements for Primary Cementmg," Journal of Petroleum Technology, May 1966. .3 Root, R. L. and Calvert, D. G., "The Real Story of Cement Expansion," Paper SPE 3346, Presented at Rocky Mountain Regional Meeting, Billings, Mont., June 2-4, 1971. fWBeirute, R't "Expansive and Shrinkage Characteristics of Cements Under Actual Well Conditions," Journal of Petroleum Technology, Aug. 1973'. 55Beirute) R., "True Expansive Characteristics of Commercially Available ExpansIve Cement Under Actual Well Conditions," Paper SPE 6013, Presented at 51st Annual FaII Meeting, New Orleans, La., Oct. 3-6, 1976. .. Slagle, K. A. and Smith, D. K., "Salt Cement for Shale and Bentonite Sands," Journal of Petroleum Technology, 1963. 81Cunmngham, W. C. and Smith, D. K., "Effect of Salt Cement Filtrate on Subsurface Formations," Journal of Petroleum Technology, March 1008. 88Ludwig, N. C., "Effects of Sodium Chloride on Setting Properties of Oil-Well Cement.," API Drilling and Production Practice, 1951, pp. 20-27. .. Ostroot, G. W., and Shryock, Jr., S., "Cementing Geothermal Wells," Paper SPE 904, Presented at The 39th Annual Meeting, Houston, Oct. 11-14, 1964. 90Cunningham, W. C., Fehrenbach, J. R. and Maier, L. F., "Arctic Cements and Cementing," The Journal of Canadian Petroleum Technology, 1972. 91Maier, L. F., Carter, M. A., Cunningham, W. C. and Bosley, T. G., "Cementing Materials for Cold Environments," Journal of Petroleum TechnologYJ Oct. 1971. .. Kljucefl. N. ¥"J Telford, A. S. and Bombardieri, C. C., "Gypsum-Cement Blend \'Yorks \'Yell in Permafrost Areas," World Oil, March 1973. 93Anon., "How BP Alaska Cements Through Permafrost," Petroleum Engineer, April 1973. H Anon., "Cement Blends Can Be Tested for Arctic Environments." Petroleum Engineer, Feb. 1977. .. Carter, L. G., Slagle, K. A. and Smith D. K., "Stress Capabilities I':'1J>roved by Resilient Cement," API Drilling and Production Practices, 1968,
Pl'.
29-37.
.
31
Cementing oil and gas wells Part 4-Practical
interpretation of
DRAG FORCE FROM CASING MOVEMENT (POS.)
CASING ECCENTRIC ANNULUS
rheology, annular displacing forces. How to avoid bypassing mud during primary cementing
DRAG FORCE, MUD ON WALL (NEG.)
DIFFERENTIAL PRESS. MOVING CEMENT ALSO ACTS ON MUD (POS.)
George O. Suman, Jr., President, and Richard C. Ellis, Project Engineer, Completion Technology Co., Houston
PRESSURE DUE TO MUD COLUMN WEIGHT (NEG.)
DRAG FORCE, CEMENT ON MUD (POS.)
1O-second summary Basic principles of mud and cement slurry behavior in the annulus, as mud is being displaced, are explained. Fluid design factors and guidelines for improving the displacement process to prevent mud channeling are given.
BUOYANCY EFFECT OF DENSER CEMENT (pOS.)
BY-PASSED MUD CHANNEL CEMENT SLURRY
A COMMONCAUSEof failure in primary cementing is incomplete displacement of drilling muds, which can leave vertical, mud filled channels in the cement. This mud may be displaced later under producing conditions to create open channels that permi t formation fluids to migrate vertically behind the casing. Even with good displacement procedures, some residual mud pockets likely will remain in irregularities in the borehole. The displacement process and key factors for improving displacement efficiency are described in this article. FLOW,
DISPLACEMENT PRINCIPLES
Two basic forces associated with drilling mud displacement during primary cementing are: Differential pressure, and cement-on-mud (fluid-on-fluid) drag forces.96 To effectively displace muds, oil well cements must exert a combination of differential pressure and drag forces of sufficient magnitude to overcome forces resisting displacement. These resisting forces are pressure, and casing-mud or borehole-mud (solid-on-fluid) drag forces, Fig. 33.96, 91 The resisting pressure is related to properties of the mud, i.e., density and gel strength. The resisting drag forces are some function of mud gel strength and viscosity and distance between casing and borehole wall. Drilling mud and cement slurry fluid properties vary in the well bore due to lack of uniform makeup and temperature/pressure effects. Annular flow area also varies as a result of decentralized casing, washouts, filter cake thickness changes, directional changes, formation swelling, etc. For most muds and cement slurries, effective viscosity (a measure of a fluid's resistance to flow) decreases as flow velocity increases.98 And with constant displacement
32
Fig. 33-Various forces acting to displace, and resist displacement, of a by-passed vertical mud column during primary cementing ., FLOW REGIMES TURBULENT
~ '%
en en w a: Ien a: « w ::J: en SLOPE IS CONSTANT
JRANSITION ZONE
I
-
en a.
'\
en en w a: a.
~
.LAMINAR
INTER~.EPT AT ORIGIN
FLOW, BPM (SHEAR RATE) Fig. 34-Newtonian fluid flow starts when pressure is applied. Flow regime and velocity profile inside pipe are shown in small drawings.
rate, flow velocity changes with variations in flow area. Such velocity changes have significant and complex effects on pressure required to maintain flow in these fluid systems.
Newtonian, non-Newtonian flow. The character of flowing fluid is described by the relationship between flow rate (shear rate) and pressure (shear stress), that caused WORLD OIL
1977
FLOW REGIMES TURBULENT
~
en C/) W II: IC/) II:
-
TRANSITION
« w J: ~
LAMINAR
en D.. ui C/) W II: D..
TRANSITION
FLOW BEGINS (G~L STR,ENGTH!
NO FLOW
FLOW, BPM (SHEAR RATE) Fig. 35-Non-Newtonian fluids exhibit pressure is applied. Velocity profiles are shown.
SPRING FACTOR, N = 1 DENSITY = 12.2 PPG f/)
CJ z
is i5
resistance of various
to flow when types of flow
SLOPE PROPORTIONAL TO PLASTIC VISCOSITY
30
:
II: 20 ...J
RPM
« is
600 300 200 100 6 3
Oil
Fig. 36-Example
DIAL READ. 30 25 23 19 10 8
I 600
use of Fann V-G meter to calculate plastic
viscosity (/lp) and yield point (t,) for Bingham Plastic Model equations. For data shown, /lp = 600 rpm reading - 300 rpm reading = 30 - 25 = 5 cpo And t, = 300 rpm reading - /lp = 25 - 5 = 20 Ibs.l100 ft.'
Law Model equations-presented in the late 1950s_101 are generally considered to be more accurate than those of the Bingham model. A recently proposed yield-pseudoplastic model that theoretically improved the above, is not widely used.102 Such models attempt to describe the relationship of shear rate and shear stress for muds and slurries. Extremely useful in analyzing the displacement process, they are not precise techniques. They should be used to determine flow regime and pressure requirements for displacement. But, results should be interpreted as more qualitative than quantitative. That is, if the analysis indicates a potential displacement problem, believe it. If it shows acceptable displacement conditions, do all that can be done to enhance the dispacement process anyway. Fluid property measurement. The Fann V-G (viscosity-gel) meter is used to measure plastic viscosity, yield point and gel strength of mud, and cement slurries.103 Field models have two speeds, to develop shear rate at 300 and 600 rpm; lab models have six speeds: 3, 6, 100, 200, 300 and 600 rpm. The lab model can measure properties over a range of speeds. However, the two speeds of the field instrument are enough to measure plastic viscosity (p.p) . and yield point (ty) used for pressure drop and flow regime determination with the Bingham model, as in Fig. 36.100 The Power Law Model requires two different fluid property descriptions. Consistency index (K') and flow behavior index (n') are also determined from the Fann V-G meter readings. Fann dial readings and rotational speeds are converted to shear stress in lbs./sq. ft. and shear rate in sec.-I, respectively. These data then are plotted on log paper and (n') is the slope of the line through the converted readings at 600 and 300 rpm and (K') is the intercept of the extrapolated straight line at unity rate of shear, Fig. 37. Details on operation of the Fann V-G meter are available elsewhere.103 104 Flow analysis
calculations.
Basic equations
for flow
analysis of Newtonian and Bingham/Power the movement. There are two basic fluid types, Newtonian and non-Newtonian. Newtonian fluids, such as water, exhibit a straight-line relationship between flow rate (shear rate) and pressure (shear stress) while the fluid is in laminar flow. A Newtonian fluid begins to flow when pressure is applied. As pressure increases, flow velocity increases, from laminar, through a transition zone (part laminar and part turbulent), to fully developed turbulent, Fig. 34. Non-Newtonian fluids are more complex; they may exhibit resistance to flow (gel strength) when pressure is applied. Fluids with gel strength can flow at very low rates in a solid or plug-like manner.OO Non-Newtonian fluids thus can have three flow regimes-plug, laminar and turbulent-with transition zones between each, Fig. 35. Drilling muds and oil well cement slurries are nonNewtonian. Extensive study has developed mathematical models that can be used to predict flow properties and pressure-velocity relationships of such muds and cements. The Bingham Plastic Model and the Power Law Model are most commonly used. The former has been utilized for drilling fluid anaysis since the mid-1940s.100 Power
WORLD OIL
1977
Law models of non-Newtonian fluids, and relevant nomenclature, are 10
t: 61 C/) ..... (Jj !XI
d.
SPRING FACTOR, N = 1
DENSITY= 12.2PPG
~.1i W ' II: IC/) II: « W J: f/)
.011. 1
(\'
S\.O~ RPM K'
600 300 200 100 6 3 ~___~I~
10
::::::::J. FANNV-GMETER SHEAR DIAL SHEAR RATE READING STRESS 1022 511 341 170 10 5 I
I
30 25 23 19 10 8 11,,1111
,
100 SHEAR RATE (SEC.-')
0.3 0.25 0.23 0.19 .01 .008 I
I
I
111_11
1000
Fig. 37-Example use of Fann V-G meter, with readings and speed, to calculate flow behavior index (K') and fluid consistency index (n') for use in Power Law Model Equations. For data shown:
n' = 3.32 (Iog,o 600 rpm read.l300
rpm read.)
=
3.32 X log,o30/25 = 0.26288. And K' = N (300 rpm read.) 1.066/100 (511)"'= 1 X 25 X 1.066/100 X 511° 288= 0.05173. 33
Summary of flow equations for fluids in casing/wellbore Non-Newtonian Newtonian
fluids
Bingham V
=
17.15 Q/(DhZ-DpZ),
Q
=
Plastic
Pt = fLVZpj25.6 (Db-Do). NR. = 928 (Db-Do)
Power Law Model
V (DhZ-DpZ)/17.15
For all fluids and models typ)I/Z
PI = I1pVL/1,500(Dh-Dp)2 + ty L/225 (Db-Dp). Where: V < V.
Where: V ~ V.
P, = f L VZp/25.6 (Db-Dp), NR. = 2,965 (Dh-Dp)
V pill
fluids
Model
V. = 1.62 I1P+ 1.62 [I1pZ + 8.2 (Dh-Dp)Z (Db-Dp) p PI = 11VL/1,5OO (Db-Dp)Z, Where: V < V.
annulus
*Y. = [NR.' K'96-'/1.86
(Db-Do)-'
p]1/(Z-n')
P = 0.039 L p V2f'/(Dh-Dp)
Where V ~ V. V p/l10
*Power Law Model V. calculations frequently assume NR.' = 3,000. Since NR.' for critical flow varies as a function of n', the following values are sometimes used (Source Fig. 39): n'
n'
NRe/
0.2 0.3 0.4
0.5 0.6 0.7
4,800 3,500 3,500
Nomenclature for flow equations
Db = Ho)e diameter, in. .Dp = Casing OD, in. f = Friction factor (Bingham-Newtonian, Fig. 38) f' = Friction factor (Power Law, Fig. 39) K' = Consistency index (Fig. 37) L = Length, ft. p.= Viscosity, cp p.p= Plastic viscosity, cp (Fig. 36) n'= Flow behavior index (Fi~. 37) Nn. = Modified Reynolds Number (Bingham and Newtonian) Nne' = Modified Reynolds Number (Power Law) P = Pressure drop, psi P1= Pressure drop, laminar flow, psi Pt = Pressure drop, turbulent flow, psi Q = Pumping rate, bpm p = Density, ppg t7= Yield point, Ibs./l00 {t.' (Fig. 36) V = Velocity of fluid in annulus, ft./sec. V. = Critical velocity, min. for full turbo flow, ft./sec. shown in accompanying tables. These equations can be used to calculate pressure drop, critical flow rates and to determine flow regimes.105 Complete pressure drop and flow analysis calculations, even with electronic calculators, are tedious but acceptable results can be obtained. Computer facilities in most service companies, and many operating companies, have made more detailed flow analyses practical. For example, variations of flow area due to borehole irregularities, and presence of more than one type of fluid can be easily considered. However, with computerized analyses, the analytical procedure, the type of mathematical model
Example flow calculation results Hand calculated for 12 bpm flow over 1,000 ft. in two different annuli, using fluid data from Figs. 36 and 37. * Function
V V. PI P, P
Na.
NRe'
Bingham Plastic Model 5 X 7U** 5 X 8** 4.9 6.48 6.17 6.23 40'" . N.A. 56.5 N.A. iii,340 ......
N.A.
......
5
Power Law Model 5 X8 X 7U 6.48 4.9 5.29 6,25 t 5.11+t 6.03 ...... ...... 34.5 23" 4,262
'2,789'
*11= 5 cp; ty = 20 Ibs./100 ft.z; p = 12.2 ppg; n' = 0.26288; k' = 0.0517258. **5~" casing in 7U" and 8~" wellbores. tReynolds Number = 3,000. ttReynolds Number = 4,000, selected from Fig. 39. ~Note close correlation of hand calculations to service company computer calculated results shown in text.
34
NRe'
n'
NRe'
3,500 3,500 3.400
0.8 0.9 1.0+
3,200 3,100 2,900
used and input data should be comple~ely understood, to avoid misleading results. Shown below are some example computer calculations, by various service companies, of critical velocity (Vc) of fluid, described by Fann V-G readings from Fig. 36 and 37. Note that they correspond closely to similar data calculated by hand, as shown in the accompanying table.
Service Co.
BJ Hughes Dowell Halliburton Western
Critical velocity in two different annuli, ft./sec. 5Y2" x 7%," 5Y2" x 8Y2" 5.2 5.0 ft./Sec. 5.62* 5.46* 5.31 5.14 6.60* 6.37*
'*Computer output presents critical pump rate. For comparison, these data have been converted to critical velocity. Flow regimes, pressure drop determinations. Plug, laminar, turbulent flow and transition zones for any nonNewtonian fluid are functions of velocity and fluid properties. Mathematical determinations of veloci~y at which turbulence is fully established have been based on some form of Reynolds Number for both models. In the Bingham model, 3,000 was used to derive critical velocitythe minimum velocity that will maintain full developed turbulent flow. In the Power Law Model, Reynold's Number has varied; 2,100 and 3,000 have been used although the latter is more generally accepted. More than one organization prefers to use a sliding value based on flow behavior index, n', Fig. 39. Pressure drop determinations with Power Law equations or the Bingham model for turbulent flow use friction factors taken from a Stanton-type diagram. The Modified Reynolds Number (Bingham model) is calculated and used to find friction factor (f) as shown in Fig. 38.106 The Modified Reynolds Number (Power Law Model) is used to find friction factor (f'), Fig. 39101 Displacement pressure. A non-Newtonian fluid in either turbulent or plug flow has a flatter velocity profile, across the area of flow, than when it is in laminar flow. Thus, cement in turbulent or plug flow will exert a more WORLD OIL
1977
cussed later in this article.
.02
a: .01 o .008 ....
~
.006
~ ~ .002 a:
u. .003 .004ICLMN TUBULARS INTERNALFLUSH
u.
.001 2,000
10,000
100,000
1,000,000
REYNOLDS NUMBER, NRE FROM BINGHAM PLASTIC OR NEWTONIAN EQUATIONS
Fig. 3S-Friction factors for use in Bingham Plastic Model or Newtonian fluid equation, see table. Example use: For calculated N". of 111,340, read f = 0.0067 (after Ormsby).'"
...
0.01'
"-
---
---
n'
g5 0.008 0.006
b z
0.004
i= ()
0.003
if
0.002
0
0.001 1,000
4,000 10,000 20,000 40,000 REYNOLDS NUMBER, NRE' (FROM POWER LAW MODEL EQUATION)
100,000
Fig. 39-Friction factor, f', for use in Power law Model equations. Note that NRC'for critical velocity varies with n'. Example use: For n' = 0.26288, derived from Fig. 37, and calculated NRc'= 4,262, read f' = 0.0041 (after Dodge et al).'o' >....
o
1.2
~
1.0
9
W:~HOLE
100% STANDOFF
ci 0.8 > ~ 0.6
~
>....
10(1)
(CENTERED)
~SING
00 (2) wO,MIN. STANDOFF
Drag force is the other basic mechanism that displaces mud from the casing-wellbore annulus. Drag forces that aid in displacement exist between mud and cement at the fluid-to-fluid interface or contact plane. Displacement drag forces increase with increasing velocity of cement at the contact plane and with increasing pressure between mud and cement. These forces develop after a portion of mud has been bypassed and a cement-mud contact plane exists, in alignment with the direction of flow. Resisting drag' forces exist at contact planes between mud and borehole wall and between mud and casing. When casing is not centered, resisting drag force effects will not be uniform across the annular flow area. This difference increases with decentralization and increases the likelihood of bypassing mud on the narrow side of the annulus. An indicator of the degree of decentralization is percent standoff, and investigations have shown that standoff increases the velocity required to initiate mud flow from the narrow side of the annulus, Fig. 40.96 Resisting drag forces have an effect on displacement efficiency that is also proportional to mud gel strength, i.e. higher gel strength increases differential resistance to flow across a non-concentric annular area. Under conditions that contribute to mud bypassing in an eccentric annulus, drag forces at the cement-mud interface should cause erosion of the bypassed mud. This erosion will reduce the area of contact between mud and casing and mud and borehole. If cement-on-mud drag forces are high enough to cause mud erosion, and contact time is long enough, complete mud removal should be achieved. However, those conditions are most likely to exist when cement has adequate "contact time," with a high velocity difference between cement and mud achieved only with cement in turbulent flow.lo7 Contact time is defined as the period during which a position in the annulus (generally above the zone of interest) remains in contact with a cement slurry that is in turbulent flow, Fig. 41. The resisting drag force between mud and casing can BOREHOLE
0.4I
I
I
33'13'/. 6" CASING IN 9" BOREHOLE FLUID DENSITY = 10 PPG PLAST. VISC. = 10 CP YIELD STR. = 10 LB.l100 FT.'
o o -'
w >
..."1
.'~
Fig. 40-How decentralization affects velocity on the narrow side of the annulus in relation to over-all rate of flow for one set of fluid and hole conditions. Example use: With 50% standoff, fluid in narrow side will not move before average flow exceeds 10 bpm; above 20 bpm, it is never more than 60% of total flow rate. Standoff % = 100 Wn/radius (1)radius (2). (after McLean et al)."
NEAT TAil SLURRY CASING
uniform displacing force against the mud in the casingwellbore annulus. In laminar flow, cement has a parabolic velocity profile across the area of flow and it is likely to "telescope" through the mud, leaving bypassed channels. Knowing displacement pressure and flow rate that will keep a slurry in turbulent or plug flow in the annulus is essential for primary cement job design. Physical limits of pumping equipment and well bore formation strength also have to be considered to determine what flow regime can be established and maintained. These will be dis-
WORLD OIL
1977
',"
TOP PLUG
TURBULENT
lEAD SLURRY TIME, T1
TIME, T2
Fig. 41-Mud displacement is improved by additional contact time, the period during which a point, A, is in contact with slurry in turbulent flow. Contact time in minutes = T, - T, = VT/235.6Q; VT = Volume of slurry in turbulent flow, Q = dis-
placement rate, gal./min. (after Brice et al).'07
35
be altered to a positive mud displacing force by rotating the casing while displacing cement.96 This positive effect is illustrated in Fig. 42. Reciprocation-moving casing up and down-exerts a somewhat less-positive displacing drag force. However, reciprocation also affects velocity of cement and mud, as will be discussed later. HOW TO IMPROVE MUD DISPLACEMENT It is necessary to operate within limiting conditions of the borehole, and control certain variables, to develop best displacement pressure and most positive drag forces during primary cementing. The following is a discussion of: Conditions that limit different aspects of displacement and controllable variables in the system. Centering pipe in the borehole creates a uniform annular flow area perpendicular to flow direction, and minimizes variation of resistive drag forces across this flow area. This concept has been encouraged for over 30 years.108 Centralizers do not provide perfect casing-borehole concentricity. But they will subs~antially improve standoff conditions, as casing without centralizers will lie against the borehole wall. Mechanical centralizers are available for nearly every possible casing-hole size combination. However, use of these devices is strongly resisted-under certain conditions-by some drilling personnel. Generally, this resistance is due to a concern that they will "hang up" and prevent casing from being run to desired depth. Unfortunately, conditions that generate greatest concern about centralizers-like highly deviated wells with numerous washouts-are, many times, the very conditions that make their use one of the key requirements for success. In some cases, centralizers can actually increase chances of getting casing down, i.e. where differential sticking is a problem, see Part 1 of the series. Rotating vs. reciprocal casing movement. Either type of pipe movement alters drag effects between mud and casing, to a positive displacement force from a resistive displacement force. But based on model studies/6 rotation appears to be more effective than reciprocation .in removing bypassed mud, where casing is severely off center. In addition to the mud-casing drag forces, there are cement-casing drag forces that also aid displacement. During rotation, cement-casing drag forces are more effective than during reciprocation, as they tend to "pull" the cement into the bypassed mud column instead of alongside it. Rotating casing at 15-25 rpm provides more pipe movement relative to annular fluids than reciprocating 20 feet on a one minute cycle. Therefore, in addition to the more effective direction of casing related drag forces, rotation generates more total drag force during displacement. Reciprocating can cause lateral casing movement, or changes in standoff, as centralizers move across wellbore irregularities. This lateral movement alters the flow area and encourages bypassed mud displacement. Pressure velocity surges. Reciprocal movement also affects flow rate and velocity of fluid in the annulus, Fig. 43. During the upstroke, velocity in the annulus decreases, as part of the fluid pumped out of the shoe occupies the volume previously occupied by the casing and fluid inside 36
MUD ALMOST REMOVED
CASING ROTATION STATIONARY 8TARTED FLOWING CEMENT
Fig. 42-Rotational displacing drag force aids in removal of by-passed mud in the narrow side of an eccentric annulus (after McLean et al).oo
--
o C\I
--
0 0 ""
00_ ....
EXAMPLE:
o o
FOR Q = 20 BPM. 9%" CASING.
~2:..
CYCLE TIME = 1.0 MIN. ANNULAR FLOW (UPSTROKE) = 20 + 5 = 25 BPM ANNULAR FLOW (DOWNSTROKE) = 20 - 5 = 15 BPM I:
10.5
--
1.0
1.5
2.0
2.5
3.0
CYCLE TIME FOR A 20 FT. STROKE. MINUTES
Fig. 43-Effect of reciprocal casing movementon annular flow rate. Maximum displacing rate assumes uniform acceleration, deceleration over 4 feet at each end of stroke. the casing. On the downstroke, the casing acts like a piston, displacing fluid in the wellbore below the shoe up the annulus, along with the volume of fluid being pumped through the shoe. This motion creates substantial pressure and velocity surges in the wellbore, Fig. 44,109 which improve the erosional effect of cement on bypassed mud by substantially increasing displacing drag forces. However, it is very important to know the magnitude of pressure changes to avoid breaking down the formation and causing lost circulation. This problem will be discussed later in this article. Pipe moving techniques. A power swivel should be used to rotate casing to avoid over-torquing the connections; such forces should not exceed casing makeup torque. Thread compounds with Teflon and/or Silicone additives should be avoided where high torque ranges are WORLD OIL
1977
required for rotation. The low friction character of these compounds may allow over-torquing and excessive makeup that exceeds pin or collar yield strength. Equipment is available that reciprocates and rotates casing simultaneously. A recently published review of this method, compared to reciprocation alone, showed definite improvement in success ratio of primary cementing jobs in conventional completions with small annular clearances in Exxon Co. development wells drilled in the Texas Gulf Coast.ll0 While reciprocating, pick-up loads clearly have to be less than pipe tensile strength. And it is important to note that casing weight variation will occur during the completion operations, Fig. 45.111 The difference in indicator readings on upstroke and downstroke is very important. This difference indicates whether casing is moving freely or is tending to stick. While circulating and conditioning mud prior to cementing-with casing on bottom-the difference between upstroke and downstroke weight decreases, Fig. 45, with improved mud conditions, i.e. lower gel strength and plastic viscosity. Then, the indicator will reflect weight increase from pumping heavier cement into the casing. As cement displaces mud up the annulus, there is a weight reduction, but difference in upstroke and downstroke weight should remain fairly constant if casing is moving freely. Stuck pipe is indicated by an increase in the weight difference on up and down strokes and not by weight increase alone. Standoff rings. Mechanical devices can be used to minimize frictional forces between casing and wellbore that resist movement during mud conditioning and cementing. Centralizers that rotate on the casing also reduce rotational resistance. . Other devices that aid pipe movement are positive standoff rings. These tools ride freely on the casing between collars, and they have ODs slightly larger than collars. Normally located above zones of interest, these rings act as bearings, reducing contact area between casing and formation, to substantially reduce forces required to move casing in either reciprocal or rotational motion. This equipment is recommended for: Highly deviated wells, where differential sticking is expected, or where any conditions are expected that would make casing movement difficult. Scratchers. Casing centralizing and movement was developed as a "package" that included use of scratchersmechanical devices designed to remove filter cake and, theoretically, improve the surface for cement bonding, directly to the formation. This may be the case opposite non-permeable zones, where no filter cake has formed. However, scratchers likely remove only the outer, softer portion of the filter cake that has built up opposite permeable zones. This should positively affect cementing, but if total cake removal were achieved it could create lost circulation or other problems related to cement dehydration. Placing scratchers opposite washouts should improve mud displacement. Also, scratchers mechanically disturb mud gel strength and induce added turbulence. Well bore
formation
WORLD OIL
1977
pressure
limits.
Every borehole
has limits on bottomhole pressures. The lower limit must be high enough to prevent entry of formation fluid and to stop formation sloughing. The upper limit must be lower than pressure that would induce formation fractures and cause los~ circulation. Clark presented a graphic view of typical bottomhole pressure variations during normal drilling and completion and a theoretical bottomhole pressure chart where formation strength was exceeded.112 Review of the drilling history should help identify pressures that existed in the wellbore during drilling. If kicks were encountered and formation fluids entered the well bore, minimum pressure limits should be clear. If lost circulation occurred, upper limits may be more definite. Many other conditions can be used to define a well's "pressure window." Fracture gradient knowledge is important in determining safe slurry density and/or pump rate, and whether stage equipment is needed. A profile showing fracture gradient vs. depth is desirable. Such a profile, to be discussed in a following article, enables systematic design approach. However, accurate fracture gradient profiles are not always available. Indications of fracture gradient are obtained for a given area through: The presence of lost circulation during drilling, and records of breakdown pressures encountered during stimula~ion and squeeze operations. Occasionally, operators invest an extra effort to make systematic and intentional measurement of breakdown pressure. One company obtained breakdown gradients with drilling mud in open hole as part of the normal plugback and abandonment procedure for offshore exploratory wells,11a And attempts have been made to determine fracture gradient through log measurements.lla.116 Effects of pipe movement on wellbore pressure have have been defined in the literature. 111-120There is general agreement that accurate determination of swab-surge pressures associated with pipe movement requires consideration of properties of the systems at work in the wellbore. This includes fluid properties and regime determinations and an accurate prediction of borehole ID variation. Hand calculations required ~o do this accurately are complicated and time consuming. Therefore, computer programs and nomographs have been used to simplify analysis and predict swab-surge pressures for a given set of well conditions. Many operators and mud companies have computer programs available for de~ermining surge pressures due to casing running. This information is essential, to determine what running speed to use to stay within limits (the pressure window) of a well. Condition mud before cementing. Reducing gel strength and plastic viscosi~y greatly improves displacement efficiency, and it reduces pressures required at the cement-mud interface to displace mud. It also reduces displacement drag forces required to erode and remove bypassed mud by reducing casing-to-mud and wellboreto-mud resistive drag force effects described earlier. Under certain, well defined, pressure window limits, it may be desirable to lower mud density, along with gel 37
strength and plastic viscosity, nearly to the minimum wellbore pressure limit. This would permit a larger pressure increase for displacemen~ pressures. If this is done, pipe should only be rotated, to prevent a swabbing action that may reduce pressure below the lower limit. . In most cases, mud circulation to clean up the hole and remove cuttings from the mud should be adequate if good mud properties were maintained while drilling the final portion of the hole. Casing running tips. The final steps of: Making up the last casing joint (landing joint) and the cementing head, establishing circulation and starting to move the pipe requires careful planning and a well coordinated effort. With good hole stability and an accurate casing tally, it is possible to pick up the landing joint prior to tagging bottom. If possible, the cementing head should be made up on the landing joint, otherwise it should be on the rig floor, checked and ready for makeup. Casing should not be stopped within 15 feet of bottom or with less than 10 feet between elevator and spider as this is the minimum space to permit adequate weight slack-off to overcome most differential sticking tendenCIes. With the casing "free" it can be picked up to verify ability to reciprocate. Maximum resistance to casing movement is experienced at this time and maximum pick-up load should be accurately defined to avoid overstressing the pipe. With casing 10-15 feet off bottom, final mud circulation should be started-slowly-while moving the casing. As circulation progresses, pressures normally decline as mud gel strength and plastic viscosity (shear stress) decrease with slowly increasing pump rates (shear rate). The minimum amoun~ of mud circulated prior to mixing cement should be the casing's volume. This verifies that float equipment is clear of foreign objects. It may be desirable to circulate even longer if circulating pressures are abnormally high. Mud contamination effects. The possibility of mIxmg cement and mud always exists during pumping and displacement. Such contamination can result in: Accelerated or retarded thickening times, reduced cement compressive strength, reduced bond strength (see Fig. 3, Part 1), increased filtrate loss (higher than in either mud or cement); and with oil base mud, the mixture may become an unpumpable mass.121-126 An API study showed that inorganic chemicals have an erratic effect on oil well cements,123.124 but generally tend to accelerate-the effect depends on concentration. Organic chemicals generally retard, and may completely inhibit cement set in some instances. Severe thickening with oil muds occurs with cement mixing because such muds are thickened by water wet solids that are readily available in the high solids content cement. The small average cement particle size and large particle surface area contribute to the thickening problem, which is most serioU's when oil base mud and cement slurry densities are high. Also, oil emulsion muds often contain calcium chloride in the water phase, which can accelerate setting. Pre-job tests at various oil mud/cement slurry ratios can indicate extent of potential thickening problems. 38
+500
MAX. PIPE VELOCITY
+400
+300
'0 Q.
GEL
"
+200
BREAKS
a: ::::>
00 w
a:
::::> 00 00
+100
M:! a..
o
-100 PIPE STOPPED~ -200 1
o
PIPE LIFTED TIME
Fig. 44-Measured pressure surges associated with picking-up and running of a single casing joint. Casing was lowere
CjCj z Za: ZOO ::::>< 0 I- a:() < ()
15 lJ: Cj ijj 3:
CONDITIONING
I
()
HOLE UPSTROKE
--------I
F xZ _w ::!:::!: w
--"
,/
-'-' -
I I DOWNSTROKE
EQUALIZATION
I
ECj II
TIME Fig. 45-Pipe weight on indicator on upstroke and downstroke indicates whether casing is moving freely. Changing weight reflects mud gel strength changes and density differences as cement is pumped, but difference between up and down stroke should remain fairly constant if pipe is free (after Barkis).'''
To prevent mud/slurry problems, it is best to minimize contact. The bottom wiper plug prevents contamination in the casing, and a spacer fluid reduces cementWORLD OIL
1977
(!J > «
fied on every cement job. Selection of amount and type of spacer depends on type of mud being used and interreaction problems between cement and mud. A water flush, normally in turbulent flow, may aid mud displacement efficiency. Salt water has less tendency-than fresh water-to cause shales to swell or slough. However, fresh water, salt water or fluids containing dispersing sur f act ant should not immediately precede a high density cement slurry as thinning and weight material settling may occur.
1.2
-
1.0
~ a:
0.4
il ~ o 0.8' a: a: « ~ 0.6 o
DENSITY = 10 PPG PLAST. VISC. = 10 CP 6" CSG IN 9" BOREHOLE 50% STANDOFF
> IU oJ W >
Fig. 46-Effect of fluid yield strength on velocity required to initiate flow in narrow side of eccentric annulus, for Bingham Plastic fluid with turbulent flow through annulus, see Fig. 40 (after McLean et al).'6
3.0,
MUD PLAST. VISC. = 10 10 YIELD PT. = 9.5 DENSITY, PPG = 5.5 DIA. HOLE, IN. = STANDOFF = 80%, 1 In.
2.8' 2.6
CEMENT 30 50 13.8
DISPLACEMENT RATE, RHEOLOGY DESIGN Generally, high displacement rates improve displacement efficiency if cement can be in turbulent flow up the annulus. Conditions that may prevent such flow include: Limited displacement rate capability (pumping equipment), a pressure window that limits displacement pressure and improper flow (rheological) properties of mud and/or slurry. Providing extra pumping equipment is basically an economic decision, if wellbore conditions can tolerate higher displacement pressures. Formation conditions that determine the pressure window are fixed, and attempts to exceed those pressure limits may create serious problems.
2.4' a: 0 lt) « u.. w ::E ::> ....J 0 > Ia]
2.2 2.0 1.8 1.6
::E
w t)
TOP ON NARROW SIDE I 3 10
I 5
I 10 -20
I 15 PUMP RATE. BPM 30
40
FRICTION PRESSURE LOSS FOR MUD, PSI/1,OOOFT.
Fig. 47- Type of curve that can be designed for individual conditions to determine additional cement, to assure coverage of the narrow side of eccentric annulus. Multiply volume factor times volume of annulus from shoe to desired cement column height. Example: At 5 bpm: To get cement to 1,000 feet above the shoe on the narrow side, requires 1.6 times the 1,OOO-foot annulus volume. Final cement top on wide side will be 2,200 feet above shoe. Note how volume factor decreases with higher pump rates (after Graham)."
mud contact in the annulus. Two bottom plugs may be required-one ahead, and one behind the spacer fluid-to prevent mud-cement contamination if: Contamination would create serious problems, and the spacer fluid does not by itself strip the mud film from the casing bore. A single bottom plug, ahead of the cement, will remove the film and accumulate mud ahead of the plug and behind the spacer fluid (see Fig. 7, Part 1). This accumulated mud then can contaminate the cement. A variety of spacer or preflush fluids are available, including water, brine, solutions of acid phosphates, die'Seloil (weighted or unweighted), oil base fluids and emulsions (oil in water, water in oil). Compatibility of both spacer and mud, and spacer and cement should be veriWORLD OIL
1977
Use of dispersants. The value of properly conditioned mud has been discussed. Fluid properties of the cement slurry can also be altered, i.e. dispersants can be added to lower gel strength to attain turbulent flow at lower displacement rates. This can be desirable where high pump rates would otherwise be required. By adding dispersant and lowering pump rate, an increase in effective contact time can be realized, along with the desired velocity profile. However, if turbulence can be achieved at reasonable pump rates without dispersants, the resulting displacement should be better, i.e. turbulent flow is better than laminar flow, but additional turbulence may not be "better yet." After turbulent flow is established, displacement efficiency increases with increased slurry flow resistance, as displacing drag forces increase with increasing contact pressure at the cement-mud interface. Thus, thinning the slurry to get "more" turbulence is not recommended. The buoyancy effect of higher density cement slurry on lower density mud is a controversy in the literature...,,,,,t28 Such effects should provide a positive displacing force on bypassed mud as long as there is vertical continuity of the mud column to the top of the rising cement-mud interface. Contact pressure at the base of the bypassed mudcement interface increases with increasing height of cement. This should increase both displacing pressure and erosional effects due to increased contact pressure near the bottom of the bypassed mud column. However, if the cement bypasses a portion of mud and then ree'Stablishes complete displacement of the movable mud in the annulus above the bypassed mud, displacing drag forces may be the only effective force working to remove the mud. With these conditions, it is likely that a large portion of the bypassed mud will not be removed unless turbulent cement flow is maintained. Sufficient contact time should be provided to allow the cement-mud 39
How to improve mud displacement primary cementing
drag forces to erode away any bypassed mud; a minimum of 10 minutes is recommended.97 How to utilize plug flow. When wellbore conditions are such that turbulence cannot be achieved, displacing with cement in a plug flow regime can maintain a flatter velocity profile in the annulus.127 While drag forces are not as effective as with turbulence, they can be maximized by increasing cement gel strength as high as possible, particularly in the lead part of the slurry. Also, cement density can improve plug flow displacement when it is maintained at least two pounds per gallon heavier than the mud.127 Centralized pipe and rotational movement may improve displacement efficiency. But reciprocal movement should be avoided, as intermittently increasing cement velocity could bypass mud. Pumping rates should produce annular rising velocity not greater than 90 feet per minute. Under some conditions this cannot be accomplished by controlling pump rate, i.e. with U-tube effect of higher density cement, and/or presence of lost circulation. How to improve laminar flow displacement. Wellbore and/or surface conditions that prohibit turbulent flow may al'So prohibit plug flow. When these not-uncommon circumstances exist, an alternative is to alter cement rheological properties to increase apparent slurry viscosity. Displacement, even in laminar flow can be effective if the slurry is thicker (has higher yield 'Strength and plastic viscosity) than the mud, and if sufficient volumes are used to obtain desired cement height on the narrow side of an eccentric annulus. 96,98 One guide for cement rheological design i'S to have cement yield strength exceed mud yield strength by a factor equal to maximum annulus clearance divided by minimum annulus clearance. Even though turbulence will not be achieved, the highest practical pump rate is recommended, as the difference between mud and cement velocities on the wide side vs. the narrow side is reduced as rate increases, Fig. 46. The cement volume used under these displacement conditions should be such that the final height of cement on the narrow side i'S above any zones to be protected. This volume can be determined from design curves based on specific mud and cement properties and casing-wellbore configurations (eccentricity), Fig. 47. This data should be derived from well site measurement'S of mud and cement slurry rheological properties and calipered hole size information. The detailed design curve determination is available in the literature.98 Coming next month: Primary cementing techniques, proper use of downhole and surface equipment.
LITERATURE CITED ... McLean, R. H., Manry, C. W. and Whitake~ W. K., Mechanics in Primary Cementing," JPT Vol. 1~, February 07Clark, C. R. and Carter, L. G., "Mud Displacement Slurries," JPT, Julr. 1973. .. Graham, H. L., 'Rheology-Balanced Cementing Improves cess," O&GJ, December 18, 1972.
40
"Displacement 1'967. with Cement Primary
Suc-
I.
Center
during
pipe in the borehole
2. Move casing during mud conditioning and cementing . Rotation is best for removing mud channels from narrow side of non-centered casing . Reciprocation aids in achieving turbulence. Do not use when displacing in plug flow . Combined rotation-reciprocation is most effective when displacing with turbulent flow 3. Know formation pressure limits in the wellbore . Lower limit is that required to maintain positive formation control . Upper limit is a function of the formation's strength, its resistance to hydraulic fracturing 4. Condition mud prior to cementing 5. Avoid adverse mud-cement reactions . Use proper spacer fluids or flushes and wiper plugs 6. Control displacement rates and slurry rheology . Use high rates where turb~lence can be maintained in the widest annular area, across interest zones . With turbulent flow, provide adequate contact time for mud removal . When turbulence cannot be developed and maintained, consider lower rates to achieve plug flow in narrowest annular areas, across interest zones . If neither condition can be attained, adjust cement properties to achieve high yield strength and plastic viscosity, displace at the highest practical rate and use sufficient volume to get desired height on narrow side of eccentric annulus 00Brown, R. W., et al, "Cement Rheology-A Tool for Better Completions," 1963. Petroleum Engineer Februa .00Howard, G. c. and Clark, 'J . B. "Factors to be Considered in Obtai'!inJ! Proper Cementing of Casing," API Drilling and Production Practice, 1948, I'p. 257-272. ... Dodge, D. W. and Metzner, A. B., "Turbulent Flow of Non-Newtonian Systems," AIChE Journal, Vol. 5, No.2, June 1959. ,., Robertson, R. E. and Stiffs, H. S., Jr. "An Imeroved Mathematical Model for Relating Shear Stress to Shear Rate in Drdling Fluids and Cement Slurries," SPEJ, February 1.976. '.3 "Standard Procedure for Testing Drilling Fluids," API RPI3B, Sixth Edition, April 1976. JOt"TestinJ! Oil Well Cements and Cement Additives," API RPI0B, Nineteenth Edition January 1-974. '00 Ror;ers, W. F., Composition and Properties of Oil Well Drilling Fluids, Third Edition 1963 Gulf Publishing Co., Houston. .06Ormsby, G. S., "Calculation and Control of Mud Pressures in Drilling and Completion Operations," API Drilling and Production Prac4ices, 1954, pp. 44-55. 107Brice, J. W., Jr., and Holmes, B. C., "Engineered Casi!,B. Cementing Programs Using Turbulent Flow ,Techniques," JPT, May 1964. ... Teplitz A. J. and Hassebrook, W. E., "An InvesJIgation of Oil-Well Cementing," API Drillinc_ and Production Practice, '\94ti, pp. 76-103. .00Burkhardt, J. A., "WeIlbore Pressure Surges Produced by Pipe Movement," JPT June 1961. 11.Holt "] , J. A., "Field Proven Techniques Improve Cementing Success," Worl 0./, August 1.976. m Barkis, B., "Primary Cementing, The Critical Period," B&W, Inc., Technical Literature. no Clarki E. H., Jr., "A Graphic View of Pressure Surges and Lost Circulation,' API Drilling and Production Practice 1956, pp. 424-438. m MacPherson, L. A. and Berry, L. N. "Prediction of Fracture Gradients from Log Derived Elastic Moduli," The Log Analyst, September 1972, pp. 12-19. u'Matthews, W. R. and Kelly J., "How to Predict Formation Pressure and Fracture Gradient from Eiectnc and Sonic Logs," Oil and Gas Journal, February 20, 1967 pp. 92-106. us EatonA B. A., "Fracture Gradient Prediction and Its Application in OilPT, October 11969pp. 1,353-1,360. field uperations," U6Taylor, D. B. an Smith, T. K., "improved Fracture Gradient Estimates in Offshore Drilling Operations," API Drilling and Production Practice 1970 pp. 41-50. m C~well, W. T., Jr., "Pressure Changes in Drilling Wells Caused by Pipe Movement," API Drilling and Production Praclices~ 1953, pp. 97:1112. U8Schuh F. J., "Computer Makes Surge Pressure Calculations Useful," O&G ] , August 3, 1964. .1>Bazer D. A. and Owen, H. B., Jr.!.. "Field Application and Results of Pipe ripping Nomographs," Paper SP~ 2656, 1969. ". Fontinot, J. E. and Clark R. K., "An Improved Method for Calculating Pressures in a Drilling Weh," Paper SPE 4521', presented at Fall Meeting, Las Vegas, Nev., September 3D-October 3, 1973. m Carney, L. L., "Cement Spacier Fluid," Paper SPE 4784, presented at Formauon Damage Symposium, New Orleans, La., February 7, 8, 1'974. I22Morris, E. F. and Modey, H. R., "Oil Base Spacer System for Use in Cementing Wells ContaimnJ! Oil Base Drilling Muds," Paper SPE 4610, presented at Fall Meeting, Las VeBas, Ne!'J September 30-0ctober 3, 1973. .23Beirute, R. M., "All Purpose Cement-Mud Spacer," Paper SPE 5691, presented at Formation Damage Control Symposium, Houston, January 29-30, 1976. ... "The Effects of Drilling-Mud Additives on Oil-Well Cements," API Bulletin D-4, Corrected Edition March 1963. .23Anderson, F. M., "Effect of Mud-Treating Chemicals on Oil-Well Cements, "O&GJ September 29, 1952. '28,Tschirley, N. k., "Cementing in Oil Muds," Petroleum Engineer, May 1975. Parker, P. N., eI al, "An Evaluation of a Primary Cementing ,Technique Using Low Displacement Rates," Paper SPE 1'234, presented at Fall Meeting, Denver, Colo., October 3-6, 1965. I28Garvin, T. and Slagle, K. A., "Scale Model Displacement Studies to Predict Flow Behavior DurinJlt Cementing," IPT, September 1911'. .
j
t
WORLD
Oil
1977
Cementing oil and gas.wells for downhole
Part 5-Guidelines
equipment use, stage cementing methods, new concepts for cementing large diameter casing George o. Suman, Jr., President,and Richard Ellis, Project Houston
Engineer,
Completion
Technology
C. Co.,
1 O-second summary Concepts and applications of cementing equipment used on casing strings during primary cementing are explained along with a discussion of stage cementing, mixing and density measuring devices, and how to cement large diameter casing by the stab-in method.
PREVIOUS ARTICLES in this series have presented the basic principles of hole preparation, casing handling, cement slurry chemistry and additive selection-and how mud is displaced by the cement slurry. This article will discuss downhole and surface equipment used in conventional primary cementing, with emphasis on the common problem of lost circulation. Special considerations for each of the casing strings-conductor, surface, intermediate and production-are reviewed and new ideas are presented for cementing large diameter casmg. Realizing that this subject covers a broad range of commercially available products and that design features of the equipment mentioned may vary widely among manufacturers, it is the intent of the authors to stress basic concepts and applications, and general precautions. Equipment used in conventional primary cementing normally includes a casing guide shoe, float collar, bottom and top wiper plugs, cementing head, centralizers, mixing equipment and pumps, Fig. 48.129,130,131Rotating or reciprocating type scratchers, multiple staging equipment, external
casing
packers,
metal
petal
baskets
and
/ or
other
specialized cementing equipment are frequently required. And, resin-sand coated casing, external casing seal rings and devices for increasing the annular velocity and/or swirling cement are sometimes applied.
TYPES OF SHOES, COLLARS In most cases, except in certain shallow wells, a roundnosed shoe is run on the bottom joint to guide the casing WORLD OIL
1977
past borehole irregularities encountered while running the string. Three types of shoes are commonly used: Guide shoes (without valves of any kind), float shoes and differential or automatic fill-up types, Fig. 49. Collars have basically the same features as shoes. They are commonly known as baffle collars (without valves), float collars, and differential or automatic fill-up collars, Fig. 49. Located one or more joints above the shoe, the collar, in addition to float and fill-up functions, acts as a seat for pump-down wiper plugs. It thus indicates when cement placement is complete, and controls the amount of cement left in the casing. Since cement immediately below the wiper plug may be contaminated, the collar should be positioned to minimize the amount of contaminated cement pumped out around the shoe. The guide shoe or baffle collar has an open bore somewhat smaller than pipe inside diameter. The float type contains a check valve which prevents backflow of cement into the casing after the cement job has been completed. This feature also prevents flow into the bottom of the casing during running. When float equipment is used, the casing rides or floats down to the desired depth because it is partially empty and somewhat buoyant. When using float shoes or collars, bouyancy is controlled by the amount of fluid placed inside the casing from a surface fill-up line. The casing is normally filled at regular intervals (say every five to 20 joints). Partial filling is also required to prevent collapse of large diameter casing. Differential/automatic fill-up shoes and collars provide partial fill-up of the casing during running, using either differential pressure, Fig. 49, or-for the automatic type-a predetermined-size orifice. Most single, differential fill-up units (shoe or collar) keep the casing about 90% full, unless the well's fluid level is low due to lost circulation. An additional differential fill-up unit results in about
81
%
fill-up.
Of
course,
neither
type
of "auto-
matic" fill-up equipment should be run in combination with float equipment. Pumping fluid through some types of "automatic" fill-up units converts them to conventional float valves. In other types, a ball is pumped through the tool for conversion, Fig. 50. This type preserves the "automatic" fill-up feature if attempts are made to break circulation during running. Differential fill-up equipment is frequently used on long 41
strings to: Reduce surge pressures by permitting part of the displaced mud to enter the casing, rather than all being forced up the annulus; to provide continuous
partial fill, thereby reducing running time, and to avoid the hazard of casing collapse. Some reasons for selecting float equipment without fill-up features are: · The casing can be filled with well-conditioned mud, and entry of extraneous materials from the borehole is avoided, i.e. shale cavings, cuttings and LCM.
. This equipment .is somewhat simpler in operation and, possibly, more reliable. · It gives more positive indications of wellbore fluid gains or losses; and it offers positive downhole casing shut-off if the well tries to kick.
PLUG CONTAINER
. There is a more or less continuous and progressive "breaking" of gelled mud in the borehole. Pressure surges causing formation fracturing and lost circulation can be prevented by limiting casing running speed. Running casing at speeds which provide annular flow rates acceptable during drilling is normally safe (see Fig. 43, Part 4). Surge pressure should be calculated to determine safe running speed where clearance between hole and casing is small (Part 4). Other considerations in establishing running speed include: Presence of bridges or key seats or doglegs; proximity of the shoe to total depth, and, occasionally, the number of scratchers and centralizers. If there is lost circulation material in the mud system, "automatic" fill-up equipment should not be used. And if use of lost circulation material in the slurry is planned, bottom wiper plugs and float equipment-perhaps with the exception of flapper valve types with straight-through openings-may have to be avoided. As an extra precaution to supplement visual tool inspection, fluid can be pumped through float and fill-up equipment after make-up to verify operation before running to bottom. Following cement placement-and after bumping the top plug-the pressure normally is released. This release should be rapid, to activate the check valve. If backflow is observed, pressure must be maintained until the cement sets up. However, excessive internal pressure expands the casing and it can contract and form a micro-annulus when the pressure is released-after the cement sets (see Part 1). Float, baffle and fill-up collars are normally made with equal or greater burst and collapse strength than the casing on which they are run. For shoes, however, these design criteria are not generally considered critical, as high burst and collapse strength is not required at this location in the string after drill-out.
FLOAT COLLAR
CENTRAUZER
GUIDE SHOE
PUMPING CEMENT
Fig. 48-Main equipment components of a typical primary cement job in a moderate depth well where additional accessories such as scratchers, stage collars, etc. are not required.
42
WIPER PLUGS, CEMENTING HEADS Wiper plugs are used to separate the cement from preceding or following fluids, Fig. 51. The bottom plug also removes mud from the wall of the casing, and prevents this mud from accummulating beneath the top plug and being deposited around the lower casing joints (Part 1) . After reaching bottom, the diaphragm in the bottom plug ruptures and cement is displaced out the bottom of the pipe and around the casing. The top plug seats on WORLD OIL
1977
the bottom plug or float collar, after being displaced bottom, and shuts off flow.
to
Cementing heads are available which hold one or more plugs. When the two-plug system is used, the operator should verify that the bottom plug is, in fact, placed in the bottom position in the cementing head. A mechanical device should be used to give visual proof when the top plug leaves the head. The cementing manifold should be connected so that the plug can be pumped out of the cementing head with the displacing fluid. If the cementing head is located far out of reach, delays may be encountered in releasing the top plug and pumping may be interrupted for a period of time to the detriment of the operation. Pup joints may have to be used to keep the cementing head within reach so that such delays can be minimized. At this time the cement is usually falling down the casing on a vacuum. And displacing fluid can be siphoned into the casing below the top plug (before it is released) if the valve to the supply source is not kept closed. Since the fluid can be siphoned through the cementing pump, the valve should not be opened until the top plug has been released. Another precaution taken by some service companies is to pump a small volume of cement on top of the top plug before switching to displacing fluid. A bottom plug is not recommended with large amounts of lost circulation material in the slurry or with badly rusted or scaled casing, as such material may collect on the ruptured diaphragm. Displacement of the top plug should be carefully monitored. The volume of fluid behind the plug should be determined from calibrations on the cementing unit tanks or by measuring out of a mud storage tank. Another method is to count pump strokes and convert to volume by applying a known pump efficiency. If available, a flowmeter can be used to verify volumes pumped. Pumps should be slowed as the pre-calculated displacement volume is reached, to avoid sudden bumping of the top plug and excessive pressure. A mud line pop-off valve is a desirable safety precaution. If the top plug does not bump at the calculated volume (allowing for displacement fluid compressibility), displacement should be stopped. Accurate volume measurements can be important III trouble-shooting a problem cement job, as well as in keeping track of the location of the top plug. CENTRALIZERS Casing centralizers are used to: Improve displacement efficiency (Part 4) ; to prevent differential pressure sticking (Part 1), and to keep casing out of key seats. Two general types of centralizers are spring-bow and rigid. The spring-bow type has greater ability to provide stand-off where the borehole is enlarged. The rigid type provides more positive stand-off where borehole is togauge. Special close-tolerance centralizers may be used on liners. Important design considerations are: Positioning, method of installation and spacing. Centralizers should be positioned on casing: Through intervals requiring effective cementing; on casing adjacent to (and sometimes passing through) intervals where differential sticking is a hazard, and occasionally WORLD OIL
1977
GUIDE SHOE OR BAFFLE COLLAR FLOAT SHOE (COLLAR)
DIFFERENTIAL FILL-UP. CIRCULATING TYPE
FLAPPER TYPE FLOAT
AUTOMATIC FILL-UP NON-CIRCULATING
INSERT FLOAT
Fig. 49-Examples of commonly used shoes and collars. Two fill-up devices are shown, the differential shoe or collar allows circulation while running pipe. With orifice type automatic fill-up device, high circulation rate shears the orifice retainer, converting tool to flapper type float. Insert float fits in casing collar recess between joints. (Courtesy Bakerline and Dowell)
on casmg passmg through dog-legs where key seats may exist. Effective cementing is important through production intervals and around the lower six joints of surface and intermediate casing strings-to minimize likelihood of joint loss. Particularly susceptible to differential pressure sticking are permeable zones where pressure is depleted and/or high mud overbalance pressure exists. Small clearance between casing and borehole, high deviation of the borehole and poor quality mud all increase differential sticking hazard (Part 1); proper centralization reduces the harmful effects of these conditions. Although centralizers may appear to be unnecessary obstructions on the pipe, they are effective and should be used where applicable. Correct positioning requires a caliper log of the wellbore so that locations correspond with to-gauge sections of the borehole. Installation method depends on type, i.e. solid body, split body or hinged. The hinged type is most commonly installed. Centralizers are held in their relative casing either by the casing collars or collars, Fig. 52. The restraining device collar) should always be located within type centralizer so the centralizer will pushed-into the hole. Therefore, the centralizer should not be allowed to casing joint. API has established
specifications
position on the mechanical stop (collar or stop the bow-spring be pulled-not bow-spring type ride free on a
for casing central43
FLAPPER VALVE SHEAR SLEEVE
SHEAR SCREW SHEARED
SHEAR SCREW VALVE SLEEVE FLAPPER VALVE RUNNING IN, VALVE OPEN (FILLING)
KIRKSITE BALL
~
BACK-PRESSURE VALVE RELEASED FOR CEMENTING
CIRCULATING
Fig. 50-Principle of differential fill-up operation. Pressure area differential on valve sleeve favoring the inside makes it engage lower flapper when casing is 90% full. Circulation has no effect on tool, center, until dropped ball shears the second sleeve, permanently releasing the upper flapper, right. DIAPHRAGM
Restoring force is the force exerted by a centralizer against the borehole to keep the pipe away from the wall. Centralizer restoring force capacity is determined through API test procedures and can be presented as a loaddeflection curve, Fig. 52.133 The minimum API restoring force must equal 2 (w) sin 30 degrees-where (w) equals weight of 40 feet of medium 'Weight casing and 30 degrees represents an average hole angle-at a casing to borehole stand-off 0.67 times average casing to borehole clearance. The factor (2) compensates for doglegs and is not applied for casing sizes from 10%-20-inch. Centralizer spacing. Load-deflection curves may be used for determining spacing required to achieve desired stand-off. And it should be noted that stand-off required to prevent differential pressure sticking will normally be less than that to properly centralize casing for good displacement efficiency. The lateral load imposed on a casing centralizer is the combined effect of centralizer spacing, casing weight, hole angle, weight of casing below the centralizer and dogleg (even though minor). The equation is: Lateral
component
CAST ALUMINUM INSERT
BOTTOM PLUG
51-Top
= Steel
angle,
degrees
When a dogleg exists between centralizers, expressed in degrees per 100 feet, then
1'h
8=
1'14
'h 400
Dogleg (degrees/IOO ft.) x Spacing (ft.) 200
T = ~ m' W . L. cos e for casing sections below the centralizer (the weight of the casing in mud is a close approximation for hole angles below the centralizer of 25 degrees or less)
HOLE SIZE, 9'12" 800 1,200 1,600 2pOO2~00
RESTORING FORCE, LBS.
. -- -
Fig.52-Example of spring-bow centralizer contained by stop collar so that device is pulled into hole. Load-deflection curve for a centralizer gives lateral force on casing at various deflections. For the example curve shown''', it takes over 1,700 pounds to move the casing V4 inch off center. izers, covering specific hole sizes and casing sizes and weight.132 Starting force, permanent set and restoring force are defined and specified for individual sets of conditions. Starting force is the force required to start the centralizer into previously run casing, as determined by API test. The maximum starting force permitted is less than the weight of 40 feet of medium weight casing on which the centralizer is run. Permanent set is the constant bow height of the bowsprings after each bow-spring has been flattened 12 times. Maximum starting force is determined before permanent set-restoring force after.
44
tension
=
o c z
HINGED CENTRALIZER
+
T = Tension (pulling force) due to casing below centralizer 8 One-half the change in angle between centralizer and next lower centralizer
u..
~
weight component + 2 (T) sin 8
sin e
in mud buoyancy factor
e = Borehole
and bottom wiper plugs. Diaphragm in bottom
plug ruptures with pressure increase to allow slurry passage. Solid plug, right, follows slurry. All plug material is drillable.
-u:
Casing
W = Weight per foot of casing, pounds L = Distance from centralizer to next lower centralizer, feet
TOP PLUG
:i
=
= m.W.L.
Where: m
Fig.
load
The sign (+) for the second term depends on the direction of the dogleg (usually the sign is negative for a build-up in angle and positive for a drop-off in angle). The positive sign provides a more conservative (higher) calculated load and may be acceptable because of other unknowns in a deviated hole. Example
W
= 40.0
For: m = 0.847 (10 ppg mud); lb/ft, 9% inch casing; L 45 feet (centralizer
calculation:
=
spacing); e = 25 degrees; 916 feet of casing tralizer, and a 2 degree/lOO foot dogleg: Lateral
load
(additive
dogleg)
= (0.847)
below
cen-
(40.0) (45)
= 644 + 487 = 1,131lb. Lateral load (Subtractive dogleg) = 644 - 487 = 157 lb. Some iteration (trail and error calculation) is required in calculating centralizer spacing in this manner because a centralizer spacing must be assumed and then the lateral load on the centralizer calculated. The load then (0.4226)
+ 2 [(0.847)
(40.0) (916)]
0.00785
WORLDOIL 1977
must be compared to the centralizer load deflection curve, Fig. 52, to determine whether the desired stand-off will be achieved. If not, then a closer spa c i n g must be assumed. Rules of thumb .for centralizer spacing in vertical holes I
Surface casing-One centralizer should be placed immediately above the shoe and one at the top of each of the bottom six joints, to insure centralization and uniform placement of cement in this critical section for reasons given in previous articles. Centralizers may also be installed to improve cement placement around any critical water sands.
"
..
Intermediatecasing-One centralizer should be placed immediately above the shoe and one at the top of each of the bottom six joints. Centralizers may also be placed within the cement interval to ensure uniform cement distribution opposite critical zones. Productioncasing-Place one centralizer immediately above the shoe and one at the top of each of the bottom six joints. They should be placed on every joint through the producing zones and extending 100 feet above (and below, if applicable). Other potential problem zones, key seats, sticking areas, etc. should also be protected with centralizers. Liners-Use centralizers if clearance and hole conditions permit.
L
I
,
c
,
I,
'(
Stage cementing-Centralizers should be spaced over the cemented interval above the stage collar and one joint below, since there is no casing movement in such jobs. When used the external packer would act as the lower centralizer. B Some manufacturers provide centralizers for installation on a given casing size, with several bow-spring sizes to accommodate starting and restoring force requirements for different previously run casing sizes. Therefore, size of both casing to be installed and the previously installed casing (or hole) should be specified when equipment is ordered. WIPERS, SCRATCHERS Wipers and scratchers are used primarily to remove borehole mud cake. They also aid in breaking-up gelled mud. Both rotating and reciprocating styles are available, Fig. 53 (also see Part 4). These devices are rarely used on liners because of close clearances. Rotating type wipers or scratchers are run across the zone of interest plus an additional 20 feet above and below the zone. Reciprocating type scratchers are generally spaced at 5 to I5-foot intervals throughout the zone plus the additional 20 feet above and below. When reciprocating, the vertical casing movement should always exceed the distance between wipers or scratchers. If reciprocal movement equals the spacing, removed mud cake and cuttings can accummulate at the end of each stroke. When wipers or scratchers are used, mud circulation should always be started before pipe is moved. And pipe should be moved slowly at first. If no pipe movement is planned, these devices should not be run. MULTIPLE STAGE EQUIPMENT Multiple stage cementing consists of conventional placement of cement slurry around the lower portion of a casing string followed by placement of successive upper stages through ports in a stage or port collar, Figs. 54, 55.134 Although most stage cementin~ is done in two WORLD OIL
1977
.1
A
D
r
Fig. 53-Examples
of commonly used rotating and reciprocating type wipers and scratchers. Rotating type (A, B, C) are spot welded or clamped. Reciprocating types (0, E, F) move between stop collars or are secured in-place with driveset nails.
stages, additional stages are possible. Stage cementing can be used: When a long column of cement is required and weak formations are present which will not support the hydrostatic head; when two or more widely separated intervals are present which must be cemented (for instance, an upper high pressure gas or water sand), or when special situations exist such as in the Arctic where casing suspension is desired below the base of the permafrost. In deep, hot wells, stage cementing may also be required to. place slurry with proper temperature characteristics at the desired level, i.e. retarded cement with adequate thickening time for hot formations may not set-up if it is circulated to low temperature, shallow zones. Stage or port collars may also be used for placing special fluids in upper portions of the casing string for 45
CLOSING PLUG
UPPER SLEEVE
LOWER VSLEEVE
l 'I
)f'ri, 1
PORTS
,J1~:/
't I
o
,
CLOSED
more port collars in-place, in the closed position. The first stage primary cement job is conducted in the conventional manner. The casing then is landed. Drill pipe is run with a special tool for opening, closing and packing-off the collars. One port collar can be opened, and cement placed. That collar then is closed, the next collar is opened, cement is placed, and so on. With all collars closed, excess cement is reverse circulated. When these devices are used, an external casing packer or metal petal basket is commonly installed below the coUar to prevent cement from falling through mud in the annulus. This precaution is particularly appropriate when weak zones exist below the collar.
~..~
{..
0
,i.
%,11 '
OPEN
~bENING MB CLOSED
Fig. 54-Stage collar operation. Tool is run in closed position, left. When lower stage is complete, bomb is dropped to move lower sleeve down exposing ports, center. Wiper plug following second stage slurry, right, moves upper sleeve down closing all ports with cement outside casing. (Courtesy Dowell)
One disadvantage to stage cementing is that the casing cannot be moved (rotated or reciprocated) after the first stage has set. This increases the possibility of channeling and incomplete mud removal. Although stage cementing equipment has proven to be quite reliable, it is always possible that the collar will not close and seal completely. If this happens, satisfactory remedial cementing at shallow depths, particularly when the well is completed in deeper high pressure zones, may not be possible. However, the only alternative to use of
protection against freezing, corrosion or fault movement. Advantages of port collars are that they can be opened and closed repeatedly, Fig. 55. When wellbore fracture gradient profile is known, the stage cementing operation can be tailored more specifically to existing conditions.135 For example, high density cement can be utilized and the cement column brought above the weak zone during the first, conventional stage. After that stage has set and the weak zone is sealed-off, a column of cement which would otherwise have fractured the weak zone and caused lost circulation can be introduced at the stage collar. Other combinations of formation fracture gradients and cement densities and column height can be handled utilizing two and three stages.134 Fracture gradients in the above example were determined primarily during stimulation treatments. Squeeze cementing fracture gradient information was also utilized. Stage collars are most commonly used for this purpose, Fig. 54. The stage collar contains ports which are initially isolated by a sliding sleeve (s). The sleeve (s) can be moved downward to open the ports-and later close themwith a special bomb or tripping plug. The stage collar is used in combination with: Special plug catching bafHes, bypassing bottom and shut-off wiper plugs, port opening bomb or tripping plugs and closing wiper plugs. Typical application. The stage type tool is installed in the desired place in the casing string as it is being run.136 In the first stage, cement is circulated around the shoe and part way up the annulus-sometimes up to the location of the stage collar. After cement has been placed around the bottom of the casing, the multiple stage tool is opened hydraulically by plugs. The well then can be circulated with mud, if desired. The upper cementing operation(s) may proceed immediately, or the lower stage may be permitted to set-up. The final plug, following the upper stage cement slurry, closes the ports in the stage collar. When a port collar is used, casing is run with one or
46
t z
W D-
o
w en o-' o !
ROTATING
SLEEVE
VERTICAL ACTION SLEEVE
Fig. 55-Operating principle of two types of port collars that can be repeatedly opened or closed by rotation of tubing or drill pipe, left, or by vertical movement, right. Use of cup type packers and additional ported sleeves on the inner string (see Fig. 59) allow cement to be placed through one or more casing port collars. WORLD OIL
1977
collars-if stage cementing is absolutely necessary-is perforating, cementing and squeezing the perforations. Use of stage cementing collars is certainly preferable to this alternative.
CEMENT
STAGE COLLAR
External casing packers, available in both solid rubber and inflatable styles, are becoming more widely applied in primary cementing to reduce the cost of remedial work. The external casing packer is frequently applied in lieu of the metal petal basket where positive control is required. Packers also help centralize the casing. The use of the external casing packer and a stage collar as a pack-off shoe or collar is illustrated in Fig. 56. This combination has been effective in preventing loss of cement to rathole and contamination of the primary cement job cement with mud. Inflatable external packers and port collars have also been applied for cementing between zones to be open hole gravel packed as discussed in a previous series (see WORLDOIL'S Sand Control Handbook, page 44). MIXING EQUIPMENT, DENSITY CONTROL Dry cement must be mixed with the proper amount of water to ensure that slurry and set cement properties are as designed. Effects of inadequate or excessive water are discussed in Part 3 of this series. For most slurries, the jet mixer will provide a uniform mixture.135 Special mixing e qui p men t is sometimes required for high density cement, high viscosity cement and jobs in which precise composition and blending of all additives is particularly critical (such as liner and squeeze cementing operations). Density measurements are used to verify proper cement/water mix ratios during the job. The jet mixer induces a partial vacuum at the venturi throat which draws in the dry cement. High stream turbulence then provides thorough mixing. This type of mixer is simple, reliable and rugged. Some cementing compositions require the use of specially designed and sized nozzle units. Jet mixers are capable of handling 50 sacks per minute. One disadvantage of high pressure jet mixers is that two pumps are tied-up during the mixing operation-one mixing, the other pumping fluid downhole. Special mixing equipment available through service companies utilize a variety of mixing principles. Two basic types are "continuous" and "batch". Mixing and/or blending is achieved with continuous methods through: Cyclone or whirlpool action; recirculation; jet turbulence, or a combination of these actions. Larger "tub" storage of mixed slurry tends to improve uniformity. Mixing and/or blending is achieved with batch methods through use of: Propeller or imp e 11er type mixers; paddle mixers; ribbon blenders; pneumatic mixing, and rotation of the cement tank (similar in appearance to those used in construction). The amount of cement that can be mixed in a batch unit is limited. However, several batch type units can be combined to provide continuous operation on large jobs. Batch mixing provides the most accurate and thorough mixing of all slurry components. WORLD OIL
1977
FLEXIBLE PLUG
Fig. 56-Schematic of inflatable external packer used with a stage collar to pack off above a weak zone or open hole section. Flexible plug is first pumped to the shoe and pressure is applied to inflate the packer element. The tripping plug opens the sleeve for cementing and the shut-off plug closes the sleeve permanently. Other variations are possible using hydraulically operated cementing collars. Continuous and batch units can also be combined in series. The various types of equipment have different limits in mixing rate, storage or "holding" volume and pump rate. The service company should be consulted regarding specifications, availability and suitability of units for particular applications. Density measurements are used to control the mixing operation. Variations in density during a job can result from: Non-uniform blending of dry components; changes in the water-to-cement ratio; air entrainment in the sample, or a combination of these possibilities. Density is measured as samples with balances (two types), or continuously with radioactive devices or a force-balanced U -tube.137-139 Density is usually obtained with a standard API mud balance. The device is simple, easy to use and gives reasonably correct values when precautions are taken to avoid air entrainment. Avoid sampling the upper, aerated portion of the slurry in tub, blender or mixer. Accuracy can be improved by using the API pressurized fluid density balance in which the slurry is pressured to ahout 400 psi with a hand pump before weighing. In this device the air occupies a negligible volume.137
LOST CIRCULATION,VOLUME CALCULATIONS Lost circulation is normally handled in primary cementing by either: Using a low density slurry to prevent formation breakdown and/or using stage equipment if 47
the breakdown pressure would be exceeded by bringing the cement up in one stage. Low density slurries may be desirable for minimizing downhole pressure and avoiding lost circulation, but the high strength of neat cement may be preferred through completion intervals and around lower casing joints. Bridging material is added in only small concentrations, if at all, to avoid problems with plugs and float equipment, and bridging in the casing-well bore annulus, see table. Although high filtrate loss may be favorable for blocking fractures in permeable zones, some filtrate loss control may be desirable to prevent slurry dehydration and bridging in the wellbore annulus. In such cases, a good compromise is to use a cement with about a 200 to 500 ml filtrate loss at 1,000 psi. Bridging material should be used in primary cementing only as a last resort. If it is used and stage tools are necessary, only granular type materials should be considered. In addition, the following precautions should be taken:
applying mud pump rate and drill pipe displacement data. This can aid in determining cement volume. METHODS FOR VARIOUS CASING STRINGS Conductor pipe, and surface, intermediate and production casing strings have different requirements for accessory casing equipment and cement composition (see Parts 1 and 3). For instance, design considerations may include: The need for zone isolation; protection against bottom joint loss; whether or not the interval will be perforated; and so on. High compressive strength cement should be used at the shoe of all strings and opposite the producing zones, particularly if high pressure treating or fracturing is planned. Compressive strength should be at least 500 psi before drilling out and 2,000 psi before perforating. Conductor pipe is used to raise the circulating fluid high enough to return to the mud pits.129 It also prevents washing out around the rig base and sometimes it provides a base for blowout preventers where gas sands may be encountered at shallow depth. And it may be used to support some of the wellhead load. This pipe is cemented to the surface. Depth can be a few feet to 200 feet. Normally, an accelerated neat cement is used to provide maximum compressive strength and rotational/axial shear resistance. Minimal accessory downhole casing equipment is used. For instance, a guide shoe and top plug may be used when water is the drilling fluid and mud is not adhering to the inside surface of the casing. Precautions should be taken to avoid pumping this string (or any large diameter casing) out of the hole, as will be discussed below.
Precautions to avoid plugging . Preferably, the first and last portions of the primary cement job will not contain lost circulation material, particularly large solids. Bridging hazards are decreased when slurry free of bridging material initiates flow through restrictions. Slurry free of bridging material at the end of the job will tend to wash away solids left in collars and baffles to improve operation of floats and stage tools. And plugs wipe better with less chance of accumulating bridging material beneath the plug and stopping it prematurely. . Avoid reducing slurry bridging material carrying capacity with excess water or dispersants. Also, dilution and thinning of slurry from water in pumps, lines or spacers should be avoided. . The job should be continuous with no shut-downs. Cement volume required in primary cementing can be calculated using a caliper log and tables provided by the cementing company. An excess of 15-35% is used as a safety factor when a caliper log is used. When such logs are not available, volume is based on experience in the area and is some factor applied to the volume removed by the bit assuming no washouts. Rig crews commonly calculate hole volume by timing the circulation of marker material (oats, dye, etc.) and
Properties
of bridging Specific gravity
Type
material Size (Mesh)
Temp. limit
Cellophaneflakes.. .. .. .. ...
-
-% in.
Gilsonite.. . .
........
1.07
(8/100)
.......
1.30
(8/200)
2.40* 2.40*
(10/50) 50%(50/200) 50%( < 200)
..
1.28 1.28 1.28
% in.-(100) (10/100) (30/100)
.. ... .... ......
Crushedcoal.. . . . .
'"
About 300°F l,OOO°F
Cone. Ib./sk. \Is-Yz Normally 5-25** Normally 5-25**
Perlite Expanded. . .. .. . . . . . . . . . .
Semi-expanded.. . . . . . Walnutshellscoarse.. . . . . Walnutshellsmedium....... Walnutshellsfine. . . . . . . . . . .
Surface casing is run: To protect the shallow fresh water sands from contamination by brines; to seal off problem sections of the hole (such as caving) ; to provide support for the wellhead, and to provide blowout protection in combination with blowout preventers. Depth can range from a couple of hundred to several thousand feet and is frequently specified by government regulations. Surface pipe is usually cemented to the surface. Normally, an accelerated neat cement is used to protect a short surface casing string or the lower section of a long string. "Filler" cement is placed across the upper section because such a cement usually: Provides adequate
15-20 15-20 1-5 1-5 1-5
Comments Do not usebottomplugs,stagetool or ball typefloat equip.at over Ib./sk. Donot usemorethan25Ib./sk. with stagetools,smallannularclearance or smallpipe. Donotusemorethan25Ib./sk.with stagetools,smallannularclearance or small pipe. ExpandedPerlitetakesonwateraspressureincreasesdownhole.Perlite tendsto float in thin slurries due to entrappedair. Lowgel strength slurrieswill not carry Perlite.Somewhatfragileandwill not performas well asothergranularmaterialsunderhighdifferentialpressure. Donotusein smallannularclearancesor smallpipe. Usuallymosteffective.Not likely to bridge bottomplugor annulus. Onlysizeto usewith stagetoolsor ball typefloats.
*Absolutedensity83Ib./cu.ft.at zeropsi, 143Ib./cu.ft. at 3,000psi. **Concentrations of 2-5Ib.jsackmaybe addedto cementslurry with minimumdangerof bridging.
48
WORLD OIL
1977
axial shear bond strength and zonal isolation; it is less likely to "break-down" any weak zones, and it is less expensive than neat cement. Other aspects of slurry design may have to be considered, as discussed in Part 3, if salt zones, sloughing shales or other problems exist. Precautions may have to be taken to prevent bottom joint loss as described in Part 1, including: Strengthening the lower joints by welding or use of thread locking compound; using two plugs; using both a guide shoe and float collar, and centralizing the pipe.
11
CASING PORT COLLAR
"
,
j ,I'
:1!
I
ECP
Hanger devices are available that may be placed in the surface casing a few hundred feet above the shoe to suspend part of the weight of an inner string from that point. Intermediate casing-protective casing-is most often used to seal off weak zones that might be fractured by heavy muds used to drill deeper, geopressured zones. Conversely, this string is sometimes used to isolate high pressure zones so lighter drilling fluid can be used for drilling deeper zones with more normal, hydrostatic pressure. Intermediate casing is also used to isolate corrosive water. If only small annular fill-up is required, neat cement is used. When high slurry volumes are needed, inexpensive and low-density filler cement is followed by neat cement at the shoe. Stage cementing is sometimes required. When cementing off bottom an external casing packer and stage collar might be required as a pack-off shoe. Production casing, in addition to its borehole support function, is run to prevent interzonal flow while producing from or injecting into (such as stimulating) the production interval. High compressive strength cement is preferred in this application. Neat cement with retarder, if required, is normally used. Cement density and strength retrogression were discussed in Part 3 (two ppg more than mud weight is desirable) . Downhole equipment will normally include two plugs, using both a guide shoe and float collar. Some operators use a flQat shoe and a float collar as added insurance for positive shut-off. And "automatic" fill-up equipment is often used on production casing. Cementing large diameter casing requires some special considerations. Such casing is subject to being pumped out of the hole. This will occur when the pump or hydrostatic pressure acting on the cementing head area, equal to the casing inside cross sectional area, provides an upward force exceeding the buoyed weight of the casing. Pressure increase on bumping a plug is, of course, offset and does not contribute to the problem. Large casing can also be floated out of the hole if the weight of casing and mud in the pipe does not exceed the buoyancy provided by the annular column of cement. The possibility of casing collapse must also be considered. Heavy mud may be required to prevent these occurrences.
COLLAR CEMENT INFLATE TOOL INNER STRING I;'.
LATCH SEAL
FIRST STAGE
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1977
stab-in cementing is now a fairly comlarge diameter casing. The string is drill pipe stung into a special sealing With this method there is less likelihood
PACKER
SECOND STAGE
Fig. 57-Stab-in stage cementing for large diameter casing. (1) With seal nipple latched into casing shoe, first stage cement is pumped, and displaced with the flexible latch-down plug. (2) A ball is dropped into the cementing tool, the inner string is raised, and cups are located over ECP port to inflate packer element. (3) Tool is raised and rotated to open port collar, and second stage is pumped. Then ports are closed, and the inner string is reverse circulated for clean-up.
of pumping the casing from the well. There is less mud contamination, less wasted cement, and there is less cement to drill out. One method of stage cementing large diameter, shallow casing using an inflatable external casing packer and port collar is shown in Fig. 57. Coming next month: Liner cementing-design cation, running and cementing techniques.
and appli-
ACKNOWLEDGMENT The authors wish to acknowledge the contribution of Mr. Kerr Godfrey of Atlantic Richficld Co. who provided valuable information and data included in this article. LITERATURE
CITED
". Willard, R., Personal communication, 1977. 13. Gage, O. G., Jr., "Subsurface Cementing Equipment," Oil-Well Cemenllng Practices in The United StaJes, API (1959). pp. 109-117. 131Moscrip, R. P.) Coordinator, "Preparation of Hole, Running and Cementing Casing," Oil-Well Cementing Practices in The United States, API (I 959). pp. 101'-107. 132"API Specification for Casing Centralizers," API Spec 10D, Second Edition, February 1973 and Supplement 1', March 1976. 133Anon. "Cementing Program,' Weatherford. 134Pela, E. C,) Coordinator, "Multistage Cementing and Alternations," Oil-Well Cementing Practices in The United States, API (1959), pp. 141-147. 186Gibbs, M. A., "Delaware Basin Cementing:-Problems and Solutions," Journal of Petroleum Technology, October 1966, pp. 1281-1285. 13. Owsley, Wm. D., "Surface Cementing Equipment and Supplies," OilWell Cementing Practices in the United States, API (1959), pp. 87-89. 111
Inner string or mon practice for cemented through sleeve in the shoe.
INFLATE
Nickles, S. K., "An Instrument for Measuring the DensIty of Air En-
trained Fluids," SPE Paper
49
Cementing oil and gas wells Part 6-Liner applications and equipment used for installation. Common problems to avoid while pumping, displacing cement George O. Suman, Jr., President,and Richard C. Ellis, Project Engineer, Completion Technology Co., Houston 10-second summary Liner running and cementing methods are illustrated and applications of various types of liners are discussed. Solutions to common problems encountered in conventional and special liner cementing, and basic job design criteria, are suggested.
SURFAC~
I SURFACE L CASING
2,000-
INTERMEDIATE CASING
PORE PRESSURE
/
4,000-
6,000(NORMAL)
8,000-
FRAC PRESSURE
,/,
10,000-
LINER CEMENTINGis one of the most difficult operations associated with drilling and completion. If a liner is not effectively cemented, the well's capability to produce will likely be reduced and the advantages of the liner installation will not be realized. This article describes liner equipment, cementing applications, some associated problems and solutions.
,, ,, ,, ,, ,
12,000-
In one generally accepted definition, a liner is: A string
...' ,
16,000PRODUCTION
TYPES OF LlNlRS Drilling liners are used to permit deeper drilling operations by isolating lost circulation or highly pressured intervals and controlling sloughing or plastic formations. And in lieu of a full length casing string, the drilling liner improves drilling hydraulics, i.e. greater cross section above liner top enables use of larger drill pipe and/or reduces annular pressure drop. Production liners are required to provide isolation and support functions when casing was landed above the producing interval. A tie-back stub liner extends from the top of a liner to a point uphole, inside another string of casing or liner. The stub liner is used to: Repair damaged or worn casing above an existing liner, and to provide an added measure of protection against corrosion and/or pressure. Tie-back casing is used primarily for ning such a string protection of fresh,
50
used to extend a liner to the wellhead. I t is the same reasons as the tie-back liner.'" Runat the end of a drilling operation assures the unworn casing.
18,000-
1/
,,
,, I
TIE-BACK STUB LINER
14,000-
,
......
LINER I
I
8
10
I
I
I
I
12 14 16 18
I
20
EQUIVALENT MUD WT., PPG 20,000Fig. 58-Example of casing and liner program to seal off high pressure zones in a deep well (after Mahoney and Barrios),'''
of casing that is used to case-off the open hole below an existing casing string, and which does not extend up to the wellhead.140 Included in this definition are slotted, pre-perforated and wire wrapped screens that are placed in an open hole primarily for sand exclusion during producing operations. Such liners are not included in this article as they are not ordinarily cemented in-place. Liners that are discussed are described in the accompanying table. Wells drilled in
WORLDOIL
1977
..
CEMENTING MANIFOLD
INTERMEDIATE CASING
TIE-BACK PACKER
LINER TIE-BACK SLEEVE SETTING TOOL PACKOFF
BUSHING
(RETRIEVABLE-OPTIONAL)
HANGER GAS MIGRATION WIPER PLUG (SHEAR TYPE) STANDOFF DEVICES
LANDING COLLAR
HIGH PRESSURE GAS ZONE
FLOAT COLLAR
Fig. 60-Schematic of a liner tie-back packer used to repair a leaking liner top where high pressure gas has penetrated the cement. Packer is run after liner is cemented and cleaned out (after Lindsey).1<3
FLOAT SHOE
Fig. 59-Typical ing liner.
equipment used to install and cement a drill-
the deep basins of the United States frequently all of the liner types described, see Fig. 58.142
reqUire ..
LINER EQUIPMENT A liner is normally run on drill pipe that extends from the liner setting tool to surface. Special tools are available to perform various running, setting and cementing operations. The following equipment is discussed from float shoe (bottom) to cementing manifold (top). Equipment locations are shown schematically in Fig. 59. WIPER PLUGS
A float shoe is placed at the bottom of the liner. It contains a check valve designed to prevent back-flow of the cement. A float collar can be run above the shoe to provide a back-up check valve to assure that cement cannot re-enter the liner after displacement.143 Automatic fillup type float equipment may be selected (Part 5). A landing collar is usually run one joint above the float collar or two or more joints above the float shoe to provide space for mud contaminated cement inside the liner. The landing collar's function is to latch and seal the liner wiper plug. It prevents the liner wiper plug from moving uphole if a check valve fails and also prevents it from rotating, which aids the drilling-out operation. Liner length
is selected to extend across the open hole
WORLD OIL
1977
FLOAT SHOE DISPLACING CEMENT
INFLATE PACKERS
Fig. 61-External casing packers used to provide positive seal between open hole intervals behind drilling liner (after Cov-
lin).'"
and overlap the existing casing or drilling liner. The length of the overlap varies with operators and applications. Fifty to five hundred feet of overlap have been used in various applications. The overlap should place the hanger above any weakened or suspect lower joints in the preceding casing string. Longer overlaps are used when high pressures are 51
being isolated behind the liners, to provide more cement volume in the liner-casing annulus. Longer overlaps also reduce cement volume displaced around the drill pipe above the liner running assembly. Short liner assemblie~ have been run and set on bottom. Although the small annular clearance limits the degree of liner buckling, any buckling will result in liner-borehole contact-the worst possible position for the liner from a cement placement standpoint. Except in unusual cases where buckling is not expected or where it can be prevented through centralization, liners to be cemented should be suspended from slips set in existing casing, or the drilling liner. Equipment is available for the special application in which liners are cemented and set on bottom. A special float shoe can be run on the bottom of the liner with an extra internal left-hand thread. The liner is first run into the well. The cementing string then is run and engaged into the thread at the shoe. The liner is run to bottom on the cementing string and the cement job is completed. The cementing string is disconnected from the shoe by rotating to the right. The liner hanger is installed at the top of the liner. Hangers are usually classified by the method used to wedge slips against the casing wall. Two classifications for hangers are: Mechanical and hydraulic.141 Mechanical set hangers require manipulation of the drill pipe (rotation and/or reciprocation) to engage the slips. Hydraulic hangers are either hydraulic release or hydraulic set. The slips of hydraulic release types require slight downward movement of the hanger for setting. Slips of hydraulic set types are driven into place by differential pressure. The presence of slips between liner and casing reduces the bypass area for circulating. This reduced fluid bypass area can create a high pressure loss during circulation and cementing. Hangers are available with multiple split slips which increase the fluid bypass area and provide increased slip contact area. These should be used on long liners for added bypass area where formation strength is low, requiring careful control of cement displacing pressures.143 The liner setting tool, a rental item furnished by the liner hanger service company, provides the connection between drill pipe and liner. Swab cups attached to tail pipe144 or a pack-off bushing and slick joint are inserted into the liner to provide a seal between the setting tool and the liner, after the liner has been suspended from the hanger and the setting tool released. The tail pipe or slick joint is usually 10-15 feet long. The slick joint method reduces piston force effects of pressure on the formation. Once the liner is hung, the setting tool can be released and picked up a short distance to confirm, by indicator weight loss, that the setting tool has separated. A relatively new innovation is the retrievable pack-off bushing that eliminates bushing drill-out. A liner wiper plug can be attached to the end of the tail pipe or slick joint with a shear pin arrangement. The selection of the proper shear rating is very important to prevent premature shearing and release of the liner wiper plug. This is especially important when a high density slurry is to be used or where a large pressure drop is expected across the liner wiper plug ID. The liner wiper plug can also be latched to the tail pipe to prevent pre52
mature shearing. Release of this type can only be affected by engagement of the drill pipe wiper plug. Liner packers can be installed at the top of liners to seal between liner and casing, after cement placement. Seal elements may be rubber or lead or a combination of both. Liner top packers may be run as an integral part of the liner hanger and set by manipulation of the liner running tool. However, this type of packer should be considered only if clearance between casing and the packer element is such that the hole can be circulated at desired rates without increasing back pressure excessively on the open hole. Inadequate circulation clearance, combined with the possibility that the main sealing element could be damaged by mud and cuttings circulating past the packer, could result in seal failure. A minimum-restriction liner hanger without a packer may permit more effective cementing and desired sealing of the overlap. A liner packer does enable reversing-out of excess cement without imposing high pressure on the formation. This type packer is not recommended for high pressure gas control. . Special packers can be set in conjunction with a tieback sleeve (to be discussed later) after cementing and clean out operations have been completed. These "linertie back packers" seal both in the tie-back sleeve and against the suspending casing.143 The tie-back packers are not exposed to potentially damaging circulation and have been successful in controlling gas leakage around the liner top, Fig. 60. External casing packers have been used on liners to isolate between zones in open hole. They are inflated following cement displacement-before the cement sets upto provide more effective zone isolation, Fig. 61.145 External casing packers have also been used to seal the liner top. Liner stage cementing is possible with the inflatable external casing packer and hydraulically operated cementing collars. Tie-back liner or casing. It may be desirable to extend a liner uphole, with a tie-back "stub" liner, or to the surface with a tie-back casing string. This can be accomplished by installing a tie-back sleeve or receptacle on top of the liner hanger. The tie-back sleeve is usually polished 3-6 feet on the ID surface and is beveled on the top to guide entry of seal nipple, tools, drill bits, etc. Fig. 62. A liner tie-back sealing nipple run on the bottom of the tie-back string should be designed to fill the full length of the tie-back sleeve with multiple sealing (packing) elements to assure an effective seal even with localized damage to the receptacle ID. Cement float equipment should not be used, to avoid a pressure block which would prevent full insertion of the seal nipple into the receptacle. As mentioned, the drill pipe extends from the liner setting tool to the surface. The cementing manifold and pump-down plug dropping head are connected to the top of the drill pipe. The manifold provides a means of pumping mud and cement down the drill pipe and retaining the pump-down plug until it is to be released, behind the cement. COMMON
RUNNING
CEMENTING PROBLEMS
Small annular clearance is the primary problem in liner operations. It is not uncommon to have a 5-inch OD liner WORLD OIL
1977
extend below 7-inch casing, inside a 6y/!-inch drilled hole. With the liner perfectly centered, the annular clearance is only %6 inch. It is likely that even less clearance would exist, as a thin non-movable layer of mud cake may be present opposite permeable zones. This is less than half the clearance norma,lly achieved in casing cementing practices where, for example, it is common to run 5 1/2-inch casing into a 7 7/8-inch drilled hole. Small clearance causes high pressure losses during circulation and cement placement which increase the possibility of lost circulation. The small clearance also makes it difficult to' run liners. Swab/surge pressures can be extremely severe and running speeds should be slow to avoid pressures that could break down formations and cause lost circulation. It is frequently necessary to restrict running speeds to one stand of drill pipe every two to three minutes.146 Detailed evaluation of swab/surge pressures should be part of a liner running program. Drilling mud properties for different wells may result in substantially different swab/surge effects. Detailed computerized analytical procedures as well as simplified nomographs are available in the literature to aid in determining maximum running speeds (see refs. 118-120, Part 4). Cement contamination by mud is increased by the small clearance between liner and open hole. And restricted clearance may inhibit use of centralizers, resulting in severe eccentricity or actual borehole contact. Cement channeling or mud bypassing is most likely under these circumstances. Cement volumes are necessarily small and bypassed mud, particularly near the top of the liner, will be most difficult to remove. Even with cement in turbulent flow, and with good rheological properties of both the mud and cement, bypassed mud may not be removed due to insufficient "contact time" ,with the cement slurry.lo7 Lack of pipe movement while cementing. Although pipe movement is considered one of the most important factors in achieving a successful cement job, moving a liner while cementing is seldom' done because of the desire to be "free" from the liner prior to pumping cement. Fluid rising velocity decreases appreciably above the liner running assembly and debris and cuttings can accumulate around the drill pipe making release difficult, particularly if the mud system was not properly conditioned, prior to the job. Obtaining competent cement at the liner top with a single-stage liner cementing technique, requires that excess cement be circulated over the top of the liner through the casing-liner annulus. This operation concerns most drilling and operating personnel because premature set could lead to an expensive fishing operation or even well loss. Thus, the desire to be "free" from the liner usually precludes the opportunity for pipe movement. A recent innovation is a pressure relief sub. After bumping the plug, if release from the liner is not achieved, additional pressure (4,000-5,000 psi) opens ports and enables excess cement to be reversed out of the hole. Temperature differential. Long-liner installations may encounter problems due to a substantial temperature differential between liner top and bottom. Cement formulated to accommodate the higher, deeper temperatures WORLD OIL
1977
may require prolonged WOC time at the liner top to achieve adequate set. Where high pressure gas is to be isolated behind the liner, this problem is severe, as gas "honeycombing" of the unset cement may occur and prevent setting and desired top seal. Contamination. Mud-cement reactions may develop excessive viscosity at the interface which could increase pressure drop in the annulus. High pumping pressures could fracture weak zones or cause the fluid to be forced from the slurry and the cement to bridge in the annulus. (See Fig. 26, Part 3.) CEMENTING TECHNIQUES, DESIGN CRITERIA An effective cement seal is usually required at both ends of a liner. A good cement job on a drilling liner is one that allows drilling to the next casing (or liner) setting depth without: Having to squeeze either at the liner top or at the shoe joint, and without experiencing buckling or other liner damage. An effective production liner cement job provides a seal between liner and borehole such that remedial cement squeeze jobs are not required-basically the same as for a production casing string. Developing the seal at the top and bottom of a liner and between the liner and open hole requires effective mud displacement by the cement slurry, and cement properties that permit strength development without excessive waiting on cement time. Clearance and centralizing. A way to increase clearance would be to redesign the casing program and drill larger holes for a given liner size or, conversely, run smaller liners. Another solution is to underream the open hole. Where this is not practical over long intervals, selective underreaming opposite critical zones has been applied. However, selectively underreamed sections can be similar to borehole washouts. And effective cementing can be made more difficult, rather than simplified, under such conditions. Careful design is important. Centralizing the liner in the hole is very critical to effective cement placement. This is particularly true in deviated holes. Centralizers or positive standoff devices on the liner could be essential for success of cementing operations. However, the small annular clearance between liner and open hole often prohibits use of centralizers. Fluted positive standoff collars will improve standoff conditions. They can be run with as little as ?'4-inch clearance. Centralizers or positive standoff devices also reduce the likelihood of differential pressure sticking between liner and open hole. This makes it easier to move the liner, once it is in-place. Another innovation, intended to reduce differential sticking and improve cement placement, are helical grooves in the OD surface of the pipe; collapse resistance of such pipe should meet requirements. Moving the liner while cementing. The design of some liner setting tools and hangers makes it possible to move the liner during cementing. And moving the pipe is one factor that greatly affects cement placement efficiency (Part 4). However, as discussed, liner movement during cementing is rarely attempted. Special equipment is available that permits liner rotaS3
tion after detaching the setting tool from the liner. But, the small bearing surface area on rotation collars limits the amount of weight that can be suspended below the device. The maximum liner length to be suspended below a rotation collar should be confirmed with the manufacturer. Temperature compensation. The problem of achieving a cement seal at both ends of a liner increases with liner length, as was mentioned.147 Wide temperature variations usually require special cement formulations. It may be necessary to retard the cement to compensate for higher temperatures at the bottom. But, at the same time, it is necessary that the cement set at the lower temperatures near the liner top in a reasonable time. To compensate for the temperature variations it is essential to have accurate downhole circulating and static temperature information. Tests have shown that a cement slurry that had a thickening time of 4 hours and 54 minutes at 125°F had its thickening time reduced to only 2 hours and 57 minutes at 144°F. Temperature also affects set time and com pressi ve strength. For example, at 230°F a cement may have an 8-hour compressive strength of 1,575 psi but at 200°F that same cement may not even set in 8 hours. (Part 3) .148 Special downhole temperature recording devices have been used to measure actual temperatures to make effective cement formulation decisions. Cement design criteria. Slurry formulation for liner cementing is not simple. Each liner installation has to be examined to define hole conditions and develop the specific combination of properties that are best suited for the job. Pumping time (or thickening time) is usually designed to allow "reversing out" the cement in case of a problem. However, in wells where high pressure gas is being isolated behind the liner relatively short thickening and setting time are required to reduce chances of gas penetrating the unset cement (honeycombing). Slurry density has to be adequate to prevent formation fluid from entering the wellbore, but the combined density and displacement pressures must remain below fracture pressures of the weakest zones open in the wellbore. Normally, slurry density slightly exceeds mud density. Fluid loss additives are usually required to prevent formation damage and to reduce any tendency for building a cement filter cake that could cause bridging in the annulus. No lost circulation material should be used in liner cementing, to avoid plugging float equipment or the narrow annulus. If this material is absolutely essential for lost circulation control it should not be included in the lead or tail portion of the slurry (Part 5) . Cement volume used on liner jobs has varied from less than 100% to over 300% of the required volume. Excess volume increases the likelihood for good cement placement but it also increases the possibility of operating problems. Generally, 125-150% of the required volume based on caliper surveys is used in liner cementing efforts. One technique that has been used primarily to assure a cement seal at both the liner top and bottom is a "planned squeeze" job. The cement volume placed around the shoe is only 70-80% of the annular volume behind the
54
COARSE THREAD FOR RIGHT HAND TOOL RELEASE
FOR HANGER ASSEMBLY RECEPTACLE
Fig. 62- Tie-back sleeve and seal nipple used to connect tieback liner or casing to an installed liner (after Lindsey).'''
liner; then a secondary cement squeeze is conducted at the liner top. This technique has not had wide acceptance. The primary disadvantage is that a long gap will be left between upper and lower cemented intervals. And the uncemented, unsupported section of liner may buckle under sever stresses due to temperature and pressure changes.149 Cement testing. There are special testing schedules for liners.61 Such tests should be conducted using cement samples and additives from material to be used on the job. And the mix water should be from the field water source to "bring to light" any incompatibility between the field water and some admix and/or the cement. Spacer fluids. The plug arrangement for liner cementing eliminates the opportunity to run a bottom plug ahead of the cement. As a result, there can be a contaminated layer in the lead part of the cement slurry which may become very viscous. Normally, a spacer fluid is pumped between mud and cement to provide a buffer to avoid serious contamination. Different types of spacers have been used depending on the type of mud used for drilling and the cement slurry selected. In some instances multiple stage spacer systems have been employed to improve mud displacement and reduce chances for adverse mud-cement reactions. Spacer fluids were discussed in Part 4 of this series and additional details are available in the literature.121-12i!, 150,151 PUMPING,
DISPLACING, JOB EVALUATION
A conventional liner cementing sequence is shown in Fig. 63.152 The following precautions should be observed while pumping and displacing: When the liner is in position, mud is usually circulated, to be sure that liner and float equipment are free of any foreign material, and to condition the mud. Of course, debris and cuttings should have been circulated from the well before the liner was run to clean up the system. A clean mud system is important so that such materials will not fall out on top of the liner running assembly during the cement job. Important information can also be obtained while circulating the ,well after the liner is run. At a minimum, WORLD OIL
1977
bottoms should be circulated to the surface-a full circulation is preferred. Pump rate and pressure should be monitored and checked against the plan for the job. If a serious deviation exists, an adjustment may be required, for instance in pump rate. Fluid should be weighed and examined for gas or formation material. Returns should be gaged and pit level observed for indications of lost returns. The cement can be batch mixed, circulated through a holding tank or ribbon blender and/or double pumped in order to obtain and control desired cement slurry properties. Cement displacement rate selection should follow guidelines suggested in Part 4- for casing cementing operations. Turbulent or plug flow rates are encouraged. Such flow minimizes excess cement volume requirements. Most operators prefer to limit the excess cement volume which, of course, is pumped into the drill pipe-casing annulus. And, as mentioned, it is usually desirable to pump some type of spacer fluid (buffer) ahead of the cement. Plugs. When the cement has been pumped, the pump down plug is released and displaced between cement and mud. At the bottom of the liner setting tool and tail pipe, the pump down plug latches into the liner wiper plug, shearing or unlatching it from the tail pipe. The two plugs then move as a single plug down the liner and latch in and seal at the landing collar. Since there is no bottom plug, pump down and liner plugs wipe mud film off the ID of the drill pipe and liner. This mud collects below the plugs and can contaminate cement in the bottom of the liner. Spacing between landing collar and float shoe should be adequate to keep contaminated cement out of the liner-open hole annulus. Mud accumulations beneath a wiper plug can be substantial (Part 1). Excess cement. With cement in-placeit is standard procedure to pull the liner setting assembly out of the liner hanger. With the tail pipe above the liner top, excess cement can be reversed out. However, reverse circulation places an extra pressure on the annulus, and this additional pressure should be precalculated and controlled, where necessary, to avoid formation breakdown. A liner packer keeps reverse circulation pressures off the formation. One practice is to simply pull the drill pipe and leave cement inside the casing to be drilled out. Waiting on cement time depends on cement composition and hole conditions. Tie-back casing is usually cemented by conventionally circulating the cement. The cement job is conducted before landing the seal nipple in the tie-back receptacle. Or it can be cemented in-place, after landing and testing the tie-back connection, by circulating cement through a stage collar located above the tie-back nipple. A tie-back casing string may also be cemented by reverse cementing (cementing down the annulus).153 This technique has been used in some deep wells-above high pressure gas zones and leaking drilling liners-so that leaking gas would be conveyed up the inside of the tieback string with mud and cement returns. When reverse circulating cement into place, the cement composition can be correctly tailored to the job-for exWORLD OIL
1977
About the authors GEORGEO. SUMAN, JR., attended the California Institute of Technology and the University of California (Berkeley), graduating with a B.S.M.E. in 1952. He spent two years with Aramco in Saudi Arabia and 18 years with Shell Oil Co. working primarily with drilling, completion and stimulation design and application. In 1978 he formed Completion .Technology Co. which is actively working with a number of client companies in improving well reliability and profitability. Mr. Suman has authored many technical papers on well completion and drilling techniques and he holds numerous patents and applications in these specialties. He is a member of API and SPE and a registered professional engineer in Louisiana and Texas. RICHARDC. ELLIS graduated from the Wisconsin Institute of Technology in 1962 with a B.S.M.E. and from the University of Wisconsin in 1968 with the M.S. in mining engineering. He spent nine years with Shell Oil Co. working on design and application of artificial lift, sand control and well completions for primary, waterflood and thermal recovery operations, both onshore and offshore. His latest assignment with Shell was production engineering section leader for the Western U.S. and Alaska. Mr. Ellis joined the staff of Completion Technology Co. in 1976. He is a member of SPE and a registered professional engineer in Texas. ample, retarded cement can be used on bottom, accelerated cement on top and neat cement in-between. Pumping against the hydrostatic pressure of the cement column is not required. However, volume to displace cement to bottom cannot be as accurately determined. A tie-back stub liner is usually cemented after the seal nipple is landed in the tie-back sleeve and the tie-back liner hanger has been set. Cement is pumped and displaced down the drill pipe and liner with the liner wiper plug used to close a stage cementing collar located just above the seal nipple. With cement in-place the liner running tool is raised until the slick joint or tail pipe is clear of the tie-back liner top and excess cement is reversed out. Job testing, evaluation. With cement in the casing, a bit and casing scraper are used to drill out to the liner. Then a bit change is made to clean out cement inside the liner. I t is usually desirable to pressure test the overlap to check the seal at the top of the liner prior to cleaning out the float collar and/or float shoe. If the liner is not sealed, a cement squeeze is most easily applied at this time. The overlap pressure tests may use applied internal pressure to create a differential toward the formation. Or, where high formation pressures exist, low density fluid inside the liner may provide sufficient differential toward the borehole to indicate leakage. High differential could be assured by using a DST tool for the test. Such differential pressure should be equal to or greater than the maximum differential expected during the remaining drilling operation or during future production operations. It may also be desirable to test the seal at the bottom of a drilling liner after the float shoe has been drilled out. The test of the seal at the shoe should be conducted at 55
Checklist
DRill PIPE READY TO PUll
DRill PIPE WIPER PLUG
for equipment, cementing method selection*
. Type of liner DrilIing, production
or stub liner
. Float shoe
LINER WIPER PLUG
Fill-up or straight float type Weight, grade and joint size
. Float collar Fill-up or straight float type Spacing above float shoe Combination landing collar Weight, grade and joint size
PLUGS lATCHED TO COllAR
. Landingcollar Regular or combination with float Is ball and seat test sub to be used to set hydraulic Spacing above float collar Weight, grade and joint size
hanger
FLOAT COllAR (OPEN)
. Primary cementingaids
Centralizers or standoff devices should be compatible with hanger setting equipment Externally grooved pipe to reduce differential pressure sticking
. Liner selection
CEMENTING
Sizes, weight and grade Length Joint selection . Size, weight, grade of suspending Casing wear Slip load distribution
Fig. 63-Schematic representation of the typical liner cementing process. Liner hanging equipment is not shown (after Smith).'"
casing string
. Type liner hanger to use Mechanical or hydraulic set Single or multiple slips (bypass area) Will rotation, reciprocation be performed during cementing Hole geometry Does hanger have to pass through top of another liner .
Provisions for future tie-back string Use of setting collar only or tie-back Length of receptacle bore, 3 feet or If tie-back is completed, will liner withstand maximum internal and pected Should the setting collar or tie-back for retrievable pack-off bushing
receptacle 6 feet hanger and receptacle external pressures exreceptacle
JOB COMPLETE
a pressure equal to or greater than the highest mud weight expected to be used prior to setting another liner or casing. (See note about tests with low density fluids, DSTs). In locations where well completion is conducted after the drilling rig is moved off, feed-back on success or failure of production liner primary cementing is essential. Improved primary cementing will be realized when accurate information on the liner cementing technique and results is communicated back to drilling personnel responsible for design and implementation.
be modified
. Plug dropping head and cementing manifold Connection Latch-under type or handling sub pick-up type Is ball dropping manifold required (for hydraulic-set and ball and seat test subs) Tell-tale for plug
Coming in October: Remedial cementing, squeezing, other specialized applications. hangers
. Plugs Size, weight of drill pipe operating string Shear pin rating of liner wiper plug Displacement to shear wiper plug Displacement volume to shear liner wiper plug and bump plugs . Cement recommendations Weight, viscosity, thickening time, compressive strength, fluid loss and loss circulation material Use of bottom-hole temperature subs for information necessary to slurry design . Procedure Pre-cementing conditioning Pump rate Bottom-hole treating or break-down Spacers, flushes Displacement efficiency .
Post-cementing procedures Clean-out with mill or roller bit Preparations for completion
*After Lindseyl"
56
pressure
LITERATURE CITED ". Davis, S. H. "Cementing Liners," Chapter 17, Oil Well Cementing Practices in the United States, API, 1959. 141West, E. R., and Lindsey, H. Eo, "How to Run and Cement Liners in Ultra-deep Wells," World Oil, June 1'966. "2 Mahoney, B. J., and Barrios, J. R., "Cementing Liners .Through Deep High Pressure Zones," Petroleum Engineer, March 1974. 143Lindsey, H. E., "Running and Cementing Deep Well Liners," Three-part series, World Oil, November, December 1974 and January 1975. 1« Lindsey, H. E., "Setting Liners in Shallow to Medium Depth Wells," World Oil, May 1977. Also paper to Southwestern Petroleum Short Course, Lubbock, Texas, April 11377. "s Covlin, R. .T., "Cementing Practices-Elk Basin Field," API Drilling and Production Practices, 1968. "6 API Bulletin D-II')', Running and Cementing Liners in the Delaware Basin, Texas, First Edition, December 1974. 141Tragesser, A., and Parker, F. W., "Using Improved Technology to Obtain Better Cement Jobs on Deep Hot Liners," Preprint SPE 3891, April 1972. "0 Shell, F., and Tra~esser, A., "API Is Seeking More Accurate Bottom Hole .Temperatures," 001 & Gas Journal, July 10, 1972. ..9 Lindsey, H. E., and Bateman, S. J., "Improve Cementing o( Drilling Liners 1U Deep Wells," World Oil, October 1973. to. Carneu L. C., "Single Stage Spacer (or Deep Liner Cementing," Petroleum l!.ngineer, June 1975. '" Crowe, W. L., Griffin, T. J.J and Puntney, A. W., "Cement-Mud Spacer System Improves minois Welts," Drilline DCW, March 1977, pp. 33-34. '.2 Moore, P. L., Drilling Practices Manual, The Petroleum Publtshing Co., Tulsa, Okla., 1974, Chapter 16, "Cements and Cementing" by D. K. Smith. 153Lindsey, H. E., "Techniques for Liner Tie-back Cementing," Petroleum Engineer, July 1973.
WORLD OIL
1977
Cementing oil and gas wells Part 7-A review of cement plug placement, tubingless completion techniques and the art and science of cement squeezing George O. Suman, Jr., President, and Richard C. Ellis, Project Engineer, Completion Technology Co., Houston.
10 second summary Problems and solutions associated with cement plug placement, special methods for cementing small diameter, tubingless completions are discussed. Common misconceptions about squeeze cementing are corrected and recommended procedures are presented.
THIS ARTICLEdiscusses specialized cementing operations and remedial cement squeezing. Special cement operations covered are: ~ Placing of cement plugs in open hole or casingbailer methods, balanced placement, use of wiper plugs, special slurry design
Cased hole cement plugs are usually placed to: Abandon lower depleted zones; to plug and abandon an entire well; or to provide a "kick off point" for sidetrack drilling operations. Thru-tubing tools and techniques are available that permit plug placement without pulling tubing and killing the well.157 Open hole plug back operations can be utilized to: Abandon the lower part of the hole; isolate a zone for formation testing; seal-off lost circulation zones; and/or
WIRELlNE
DUMP BAILER
CEMENT
~ Cementing single or multiple tubingless completions-displacement problems due to small diameters, how to avoid buckling, and ~ Use of a selective completion protects the pay zone.
tool that isolates and
The extensive analysis of squeeze cementing: Corrects common misconceptions; applies the important principle of proper filter cake formation versus undesirable vertical fracturing; and describes methods and equipment for both high and low pressure squeeze cementing. CEMENT PLUGS, PLACEMENT METHODS A cement plug is a volume of cement designed to fill a length of casing or open hole and provide a seal against vertical fluid movement.154-156 WORLD OIL
1977
ELECTRICAL/MECHANICAL DUMP RELEASE
BRIDGE PLUG
CASING
Fig. 64-Dump bailer method of cement placement. Bailer of variable length is lowered on wireline. Device in bottom releases plate or opens ports to dump cement on bridge plug or sand/gravel fill. 57
initiate directional drilling. (Lost circulation cements are discussed in Part 3.) Regardless of application, the primary problem with cement plugs is contamination of the cement with drilling mud or well fluids.158.159Placement control and cement composition are critical due to the small volume of cement normally used. The dump bailer method is normally used in low pressure, cased holes at shallow depths, but it can be used in deeper, higher pressure wells with thru-tubing techniques. Applications of this method are normally limited to conditions where gravity displacement of well fluid by cement will readily occur. In shallow low pressure wells, drilling mud is not required as the well can be controlled with produced brines or field water. Sand or gravel may be placed below the desired plug interval, or a permanent type bridge SPACER
CEMENT
SPACER AND PREFLUSH
~~,~
CONDITION MUD ROTATEPIPE
DISPLACECEMENT ANb FLUIDS
iil
SPOT BALANCED PLUG
PULL PIPE SLOWLY
Fig. 55-Schematic of balanced plug method. All fluid volumes are carefully calculated so that hydrostatic pressure on plug in final location is identical in drill pipe and annulus.
DRILL PIPE
SEAT SHEARED
CEMENT PLUG TOP PLUG SEATED
BOTTOM PLUG DISPLACINGCEMENT AND FLUID
CEMENT IN PLACE
RAISEPIPE, CIRCULATE
Fig. 56-Two plug method for deeper wells or where displacement is difficult to calculate. Seat stops top plug to indicate when slurry is spotted. Pipe then is raised and additional pressure shears seat to open pipe for circulation, or reverse circulation.
58
plug can be placed at the base of the plug-unless the well is to be plugged from TD. Cement is lowered in a dump bailer on a wireline and dumped on the plug, Fig. 64. Only limited volume can be placed at one time and this must take an initial set before another batch can be dumped. In such applications there is little problem with contamination; placement depth is easily controlled and cost is low. The dump bailer has been used in open holes with lightweight drilling. mud present. Open hole inflatable bridge plugs can be used to bottom the plug above TD. The balance method is most commonly used for plug placement. Preflush, cement slurry and spacer fluid are displaced down the drill pipe with mud until cement level is about equal in annulus and drill pipe. The pipe then is pulled leaving the plug "balanced" in place, Fig. 65. This procedure appears to be quite simple 'but failures are not uncommon-and they are usually related to contaminated cement. This method is used for both cased and open hole plugs. The two plug method is used for: Placing plugs at substantial depths; where displacement volumes are difficult to calculate; and/or where cement volumes are small. The method uses a wiper-plug catcher in the bottom of the drill pipe which permits passage of bottom wiperplugs but stops and seals the top wiper plug, Fig. 66. Displacement volumes are measured, but when the top plug reaches the catcher, the event is confirmed by a sharp pressure increase, and displacement is stopped. Drill pipe then is pulled slowly above the cement plug, additional pressure shears a pin in the plug seat and circulation or reverse circulation can be established. This method reduces problems that over or under-displacement can create with the balance method. Recommendations that should reduce probability of mud contamination and increase chances for successful plug placement by balance or two plug methods listed in the accompanying table.
are
Sand filler. Some operators use sand to "improve" the "hardness" or "toughness" of a cement plug. Other operators specify that sand should not be used. Unless well temperature exceeds 2300 F, fine sand does not react with cement (see Part 3-Strength Retrogression). And compressive strength of cement at lower temperatures will decrease as sand concentrations increase. Neat cements that are densified with a dispersant have the highest compressive strength. Thus, lab testing does not support use of sand to make slurries "harder." Yet operators who specify sand use in directional plugs claim improved "hardness" and higher success ratios. Sand may improve mud removal by some type of scouring action and this could reduce mud contamination. Thus, sand may affect hardness in a manner not related to a sand-cement reaction. Cement slurries should be densified with dispersants, and sand (if used) should be angular rather than rounded. Some operators prefer mixed sand sizes grading from fine to coarse. Sand concentrations should not exceed 10-20% by weight of cement.160 Evaluate
plug location,
quality.
In simple plug backs, WORLD OIL
1977
How to minimize mud contamination of cement plugs
.
Select an in-gauge section of the hole to position the plug. A caliper log gives the most accurate evaluation, but drilling experience in the area and mud loggin~ data can be valuable aids
SMALL DIAMETER CASING
. Condition mud prior to mixing cement. Circulate bottoms up, as a minimum, and move the drill pipe. Drill pipe should be equipped with centralizers and scratchers to help remove mud cake and/or reduce cement channeling . Use preflush fluid ahead of cement-in some operations this can be water. Where chemical flushes are to be used, type will depend on mud composition and density. Oil base mud spacer should be used where oil based muds are present. With water based muds the flush can be water with a mud thinning chemical; or if density is critical, a weighted water base mud flush can be used. Preflush volume should provide at least 150200 feet of fluid in the annulus
*.
Drill pipe wiper plugs can be used ahead of and behind both preflush and cement. Wiper plugs ahead of the cement will be pumped out of the drill pipe and the wiper plug behind the cement will remain in the cement near the top of the plug. *. Use carefully calculated volumes of preflush and spacer between mud and cement to obtain equal height in annulus and drill pipe when displacement is complete. . Use a dispersant additive to densify the cement slurry; 17-18 ppg slurries can be prepared by adding 0.75-1.5% dispersant to class A, G or H cements when mixed with less than normal water. These cements develop high early strength and will tolerate a greater degree of mud contamination and still develop adequate strength after necessary woe time. A thickening time of about 30 minutes in addition to a realistic placement time is recommended . Use adequate cement volume. Minimum vertical fill for directional or sidetrack operations should be 300 feet. Anticipate that at least the top 50 feet of the plug will be contaminated with mud. It may be desirable to use excess slurry then pull tubing or drill pipe to desired location of plug top and reverse out the excess . Batch mix cement or mix thoroughly through a ribbon blender, double pump-or simply mix slow enough-to assure uniform high density slurry . After 2-3 barrels of cement clears bottom of drill pipe, pick up 10-15 feet to reduce exposure of cement to mud below the plug . Continue to rotate drill pipe until cement displacement is complete to reduce chance of cement channelin~ through mud in the annulus. Once cement is spotted, avoid rotation until pipe is pulled above the plug. * For use only with balance method
4-6 hours may be adequate before setting down on the plug to check its position. In directional work, 8-16 hours or more may be required. Provide adequate WOC time. When drilling a directional plug, check cuttings for premature drillout. If the cuttings are sharp edged and angular, cement has set properly. Subrounded or ball shaped cuttings indicate drilling is premature and additional WOC is recommended. Usually after 24 hours, inadequate set is an indication of serious contamination and the plug should be drilled out and replaced.16l Where conditions permit, an alternative is to place another plug above the first. TUBINGLESS COMPLETIONS In so-called tubingless completions, one or more tubing strings are run and cemented in the borehole to serve as both casing and tubing. Almost all equipment used in cementing conventional casing strings is available for cementing these small diameter tubulars-including: WORLD OIL
1977
Fig. 57-Possible irregular geometric arrangements of single or multiple strings in tubing less completions causes inefficient displacement of mud by cement.
Guiding equipment, float shoes and collars, multiple stage cementing collars, centralizers, scratchers (rotating and reciprocating), cement baskets and packers or basket-type shoeS.162-164 Several cementing problems that are particularly significant in the case of tubingless completions are: 1. Due to close tolerances of downhole completion/production equipment in the small "casing," buckling of the strings can create serious problems 2. Mud displacement is more difficult due to irregular geometry and lack of turbulent flow,' '.. and 3. Drill-out can be more difficult. This is. commonly avoided by placing baffles or float collars below zones to be perforated. In addition, special precautions are taken to avoid pumping excess cement on top of the upper plug.
Casing buckling is a great concern to operators utilizing tubingless completions. Special precautions used to prevent buckling include leaving pressure on the strings while cement sets to impart additional tensile loading within the cemented interval, or pulling additional tension on the string after the initial cement set to add tensile loading above the cemented interval,166 Efficient mud displacement is difficult due to the irregular geometry, Fig. 67, and lack of turbulent flow. However, successful cementing operations have been achieved165-161 by emphasizing: Casing centralization; pipe movement; increased displacement rate (by pumping through more than one casing string); relative rheological properties between mud and cement (yield point and density); and use of cement slurries having dilatant rheology, i.e. viscosity increases with shear rate. Effective use of preflushes is also important. Types of pipe movement critically analyzed in the above noted references were rotation or reciprocation (or simultaneous rotation and reciprocation) of single strings, and reciprocation only of multiples strings (rotation of multiple strings may wind the strings together and cause restrictions). "Prudent" use of wire loop type scratchers served to break up gelled mud and create flowstream disturbances to aid displacement-not to remove mud filter cake. The conclusion was that pipe movement by either 59
1
SHEAR RATE (FLOW)
Fig. 68-Four time-Independent rheological fluid characteristics in isothermal, laminar flow. reciprocation or rotation is effective. However, simultaenous rotation and reciprocation desirable for conventional completions was not economic for 2%-inch tubingless completions in 7'Vs-inch hole.167 Multiple casing strings have been cemented by pumping down only the longest string. A variation of this method is to spot cement through the longest string then lower other bullplugged strings through the unset cement. Such a "delayed setting technique" requires careful planning. Pumping through more than one string can improve results by increasing displacement rate. When two strings to be cemented are located at the same depth, they may be pumped into simultaneously. When the strings are at different depths, initiation of mixing and pumping cement into each string must be staggered. Occasionally, a string which could be landed at a shallower depth is run to bottom to increase flow velocity by decreasing annular cross sectional area. Rheology design. Efforts have been made to improve relative rheologic properties between mud and cement, i.e. yield point and density. Before cementing, if circumstances require and permit, mud returns can be watered back during the entire circulation period to lower mud weight, yield point and plastic viscosity. This increases the difference between flow properties of mud and cement. An extensive study utilizing a special computer program indicated that for 2%-inch tubing in 7%-inch hole, most desirable mud properties for maximum displacement efficiency was a plastic viscosity equal or less than 12 centipoise, and yield point equal or less than 5 pounds per 100 square feet.166 Use of cement slurries having dilatant rheology was shown to be more favorable for mud displacement efficiency.166 Due to the large annular space and limited conduit size, fluids in the annulus are almost always in laminar flow. Four possible time-independent isothermal rheologies of fluid exhibiting stable properties in laminar flow are: 60
Bingham plastic fluids; pseudoplastic fluids; dilatant fluids; and Newtonian fluids, Fig. 68. Bingham plastic and Newtonian fluids are discussed in Part 4. Water is a Newtonian fluid, and water suspensions of finely divided solids, gelled drilling muds and gelled Class H cements (Fig. 69) are Bingham plastic fluids. In the case of Bingham plastic fluids, a finite shear stress and shear rate are proportional in the laminar flow region. Shear stress and shear rate of pseudoplastic fluids are not proportional, i.e. viscosity decreases with shear rate (shear thinning). An example would be hydroxyethyl cellulose (HEC) based completion fluids. Such fluids can be non-thixotropic and should be readily displaced by cement. For dilatant fluids, Fig. 68, shear stress and shear rate are also not proportional, and viscosity increases with shear rate. This feature increases displacement forces acting on the narrow side of an annulus and on gelled mud. These fluids, therefore, increase mud displacement efficiency in the laminar flow region. The extreme differences between rheological types noted above apply only to laminar flow. Turbulent flow would tend to reduce the magnitude of these comparisons. However, turbulent flow in single and multiple string tubingless completions is unlikely. SELECTIVECOMPLETION TOOL One special equipment item which eliminates several possible restrictions to flow or production from the formation and provides unusual production or stimulation flexibility is the Selective Completion Tool developed by Gearhart-Owen Industries (see article "New completion technique keeps formation faces clean," WORLD OIL, November 1973). This tool consists of inflatable packers, a cement bypass arrangement and sliding sleeve port-type collars run as an integral part of the casing string, Fig. 70. After running casing to bottom, the equipment is properly positioned downhole with respect to the productive formation using a gamma ray log for correlation. The inflatable packers are expanded by increased mud pressure after the bottom plug seats on the baffle or collar. The bottom packer then diverts flow of primary cement from the casing-wellbore annulus into the tool's by-pass area, from which the slurry re-enters the annulus above
_
CLASS H PLUS GEL
0--0 DENSIFIED CLASS H 0-0
1-1 LlGHlWEIGHT-CLASS H 2-1 LlGHlWEIGHT-CLASS H
t
(f)
13
a: I(f) a:
iIi J: (f)
"
1200F~
/.
i£
~
SHEAR RATE-
Fig. 69-Rheology of four types of cement slurries. Class H plus gel (straight line) is a "Bingham plastic" fluid, all others exhibit "dilatant" properties (after Clark and Jenkins).'..
WORLD OIL
1977
the upper packer. Tool length can be extended to 100 feet or more by adding modules. And more than one unit and sliding sleeve may be run at one time. Cement does not contact the weIlbore through the productive formation. And flow restrictions associated with perforations are avoided, i.e. perforating debris and convergence of flow within the formation towards perforation tunnels. Production or stimulation treatment flow is established through one or more of the sliding sleeve port-type collars which can be repeatedly opened or closed by a mechanical shifting tool run on pipe or wireline. By placing such a collar just above the lower packer and another just below the upper packer, stimulation fluids may be circulated in the annulus across the productive zone to remove mud-caused impairment. Ports may be opened or closed by wireline for test purposes, or to shut-in a zone. Equipment is available for use in sand control. In some cases, greater than normal casing to borehole clearance is required. And certain components may have to be custom made for specific applications. 'REMmIAL SQUEEZE CEMENTING Squeeze cementing is the process of forcing a cement slurry through holes in the casing. The primary objective of squeeze cementing is to develop a seal in the casing-wellbore annulus between formation intervals penetrated by the casing. The most common purposes for squeeze cementing are to:16B . Repair a primary cement job that failed due to cement by-passing mud (channeling) or insufficient cement height (fillup) in the annulus . Eliminate water intrusion from above, below, or within the hydrocarbon producing zone . Reduce the producing gas-oil-ratio by isolating gas zones from adjacent oil intervals . Repair casing leaks due to corrosion or split pipe . Plug all, or part, of one or more zones in a multizone injection well to direct injection into desired intervals, and . Plug and abandon a depleted or watered-out producing zone. Squeeze cementing can 'be classified as high pressure and low pressure. And two techniques used are: Bradenhead squeeze and packer squeeze. These classifications and techniques will be discussed later in the article. Misconceptions. Techniques and technology of squeeze cementing have been developed over a period of more than 40 years,169 and later operations have proven that some early concepts were incorrect. Yet many applications are still based on these misconceptions. For example, some people erroneously assume that: I. Cement squeezed through holes (perforations) in casing under high pressure generally forms a horizontal cement "pancake" opposite the holes, thereby developing a barrier to vertical fluid movement 2. Injecting drilling mud into perforations at high pressure opens all perforations 3. High final squeeze is a positive indication of a successful job, and 4. In zones with good permeability, cement penetrates the formation without fracturing. The fundamental concept of squeeze cementing that cement filter cake forms the initial seal.
is
A cement slurry consists of finely divided solid particles dispersed in liquid. Such particles in the slurry WORLD OIL
1977
INFLATION
_INFLATABLE
ANNULAR
SLIDING
I-INFLATABLE
-INFLATION
VALVE
PACKER
BYPASS
SLEEVE
PACKER
VALVE
Fig. 7o-Selective completion tool features two inflatable packers that straddle and isolate the pay zone. Cement circulates through the tool's internal bypass and re-enters annulus above the upper packer. Sliding sleeves then can be opened to expose inside of casing to the isolated formation. Tool length can be varied (courtesy Gearhart-Owen Industries, Inc.) cannot be displaced into normal formation permeability as it would require permeability in excess of 100 Darcies to allow a normal slurry to penetrate a sand formation without fracturing.16B Therefore, when slurry is forced against a permeable formation, the solid particles will filter-out on the formation face as filtrate is forced into the formation permeability. The filter cake has much lower permeability than most sand formations. And as cake forms on part of the formation, slurry can be diverted to other exposed formation permeability. A properly designed squeeze job will cause dehydrated cement filter cake to fill the opening(s) between the formation and the casing. And, if allowed to cure, the dehydrated cement filter cake will form a nearly impermeable solid. In cases where slurry is to be placed in a fractured interval (either natural or induced) the cement solids will have to develop a cake on the fracture faces and/or bridge the fracture. Most successful squeezes in fractured formations have used a staging technique in which a highly accelerated slurry, or a slurry with bridging agents such as gilsonite or sand, is followed by a second stage of moderate fluid 61
loss slurry. This system encourages bridging and filter cake development and helps divert movable slurry to unsealed fractures. Fluid loss control. As noted above, the successful squeeze must deposit cement filter cake in openings between casing and formation.110 To achieve this it may be necessary to control cement fluid (filtrate) loss. If fluid loss is uncontrolled, cement may dehydrate and bridge off the upper portion of a perforated interval before slurry is displaced to the lower perforations, Fig. 26, Part 3. Conversely, very low fluid loss can result in very slow filter cake development and unacceptably long placement operations. Key factors that affect rate of filter cake growth are: Slurry properties (fluid filtrate loss and water-to-solids ratio) ; formation characteristics (permeability, pore pressure and fracture pressure); and squeeze pressure (differential between downhole slurry pressure and formation pore pressure). And, of course, fluid loss and filter cake growth rate vary directly, i.e. a slurry with a high fluid loss will have a fast filter cake build-up. The composition of a squeeze slurry should be based on characteristics of the formation opposite the interval(s) to be squeezed, and techniques to be used. In formations with unimpaired natural permeability, slurry with a water-to-solids ratio of 0.4 (by weight) and a low fluid loss of 50-150 cc in 30 minutes under 1,000 psi differential should provide satisfactory caking for most "low-pressure" squeeze jobs.l11 Slurry fluid (filtrate) loss can be varied and controlled as required, over the wide range of temperature and pressure conditions normally encountered in oil and gas wells, with various cement additives112 (Part 3). The WELLBORE,
FRAC. PRESS.,
VERTlCALSTRESS,
PF
"y
HORIZONTAL STRESS, "HI
I I I
I I ,
J~___~_ -...
INDUCED HORIZONTAL FRACTURE
INDUCED
VERTICAL
FRACTURE
PF~"HI or "H2 "HI or "H2<"y
Fig. 71-Effect of well depth and vertical-horizontal formation stresses on type of hydraulic fracture induced by injected fluid. Horizontal fractures will not be created if fracture pressure is less than overburden pressure, this is usually the case at depths greater than 3,000 feet. 62
important factors are rate of deposition and amount of filter cake deposited. Slurry solids content affects time required to develop cement cake and time required for adequate dehydration at a given fluid (filtrate) loss. When squeezing against shales, dense limestones, dolomites-or permeable formations where natural permeability is plugged with mud-a low fluid loss cement may not be desirable. In these situations a "high-pressure" squeeze job is usually performed and low fluid loss slurry could be undesirable' because its restricted filtrate loss could inhibit filter cake development.16D Thus, squeeze pressure, time and slurry composition are the primary controllable variables. However, these factors also are functions of formation character and type of fluid in the well, i.e. drilling mud or "clean" workover fluid. HIGH PRESSURE SQUEEZING High pressure squeeze cementing is defined as a job in which fluid pressure in the wellbore exceeds formation fracture pressure prior to or during the time that cement slurry is in contact with the formation. High-pressure methods are recommended only when squeezing relatively impermeable zones or where the squeeze is to be conducted with drilling mud in the hole. Fracturing of the formation permits displacement of mud or work over fluid through holes in the casing. The slurry then displaces this fluid into the fractures, permitting development of cement filter cake on the fracture surfaces. Where the previously-cemented annulus contains fluid or mud filled channels, fracture initiation may occur anywhere along the length of the channels-above or below the perforations. After fracturing, cement displaces and follows fluid from the channels into the fracture and cement is deposited in the channels between perforations and the fracture initiation point. Since it is likely that perforations will be at an intermediate part of any channels, only that part of the channels between the perforations and the fracture initiation point is filled with cement. Use of the hesitation technique under these circumstances may develop additional fractures and a more effective cement seal. More details on hesitation squeezing are presented later in this article. Potential Problems. With high-pressure squeezes there is no contrQl of either location or orientation of the generated fracture. The fracture will be oriented perpendicular to the least principal stress as shown in Fig. 71. Note that horizontal fractures will not be created if fracture pressure is less than overburden pressure. Formation fracturing during high-pressure squeezing may be counter-productive, as fractures induced in formations deeper than 3,000 feet are nearly always vertical. Thus, even if the casing-wellbore annulus is sealed, vertical communication between zones may be established in the fracture. Horizontal fractures containing cement "pancakes" cannot be generated by high pressure squeeze cementing in deep wells.l11 Once a fracture is created it must be sealed-off with cement, particularly if it is vertical and extends into a zone being isolated. However, sealing-off the fracture may be difficult because fracturing is usually initiated with mud, and attempts to purge the fracFures may only extend WORLD OIL
1977
them. Thus, the necessary volume of cement can be large. It is not unusual to use 100-500 sacks on a high-pressure squeeze job. Such problems with mud-filled fractures have been minimized by using a high-fluid-loss fluid (water) for breakdown. Where mud is needed for control, such fluid is spotted before setting the packer. After breakdown, cement is circulated into place for squeezing. Another problem in a perforated interval is that mudfilled perforations can withstand large pressure differentials, especially toward the formation. And, all perforations may not be forced open when the formation is fractured by the high pressure. In fact, the most common cause of squeeze cementing failures is .attributed to the unplugging of mud-plugged perforations after the squeeze job. Generally, it is recommended that solids-free workover fluids be used whenever fluid has to be displaced into the formation ahead of cement. Acid or chemical washes can also be used ahead of the slurry. Several clean-up techniques and chemical wash formulas are presented in the literature.173-177 LOW PRESSURE SQUEEZING Low pressure squeeze cementing is defined as a job in which fluid pressure in the wellbore is maintained below fracture pressure of exposed formations prior to, and during, the time slurry is in contact with the formations. In practice, "safe" squeeze pressure is usually specified as some value below established fracture pressure (300 psi has been used in some areas). Low pressure squeeze cementing175 utilizes a small volume of low fluid loss sl urry placed against exposed permeable formations with a moderate squeeze pressure. Filtrate from the slurry is forced into formation permeability allowing build-up of cement filter cake. Low fluid loss reduces dehydration rate and discourages bridging as the slurry is forced along openings or channels. In low pressure squeezes, perforations and channels must be clear of mud or other solids. If the well has been on production, such openings may have been purged. If the job is to be performed through new perforations, results may be enhanced by perforating in a solids-free, non-damaging fluid-such as filtered brine to prevent clay swelling-with pressure underbalance to permit purging of perforation cavities. In existing perforations pressure/ suction washing with or without acid may be considered. Procedure. In practice, the low pressure squeeze job is generally conducted as follows: 1. Initiate injection. Determine downhole injection pressure 2. Circulate slurry to desired location in the casing 3. Apply moderate squeeze (downhole) pressure. Consider increased hydrostatic effect of cement column 4. Restore squeeze pressure by engaging the pump as bleedoff occurs. (Note: During steps 2 and 3, cement filter cake is deposited in perforations or holes) 5. Gradually increase downhole pressure to 500--1,000 psi above pressure required to initiate flow. When bleed-off ceases for about 30 minutes, stop displacing cement slurry and hold the pressure. Do not exceed "safe" squeeze pressure. Successful squeeze jobs are routinely obtained with only one or two cubic feet of cement displaced through the perforations. 6. Reverse circulate excess cement from casing, or pull work string leaving cement to be drilled out later, if necessary. A properly designed slurry will leave only a small cement filter-cake bump (node) inside the casing after circulating out excess slurry. Improperly designed slurries
WORLD OIL
1977
FLUID LOSS (ML/30
MIN. AT 1,000 PSIIlP)
800
CEMENT NODES
150
6" CASING-
50
PERFORATIONS
15
Fig. 72-Schematic 45 minute squeeze (after Rike).173
of cement filter cake node building after with various
fluid
(filtrate)
loss properties,
can result in excessive caking with enlarged nodes, or inadequate caking and inability to hold pressure, Fig. 72. The casing can be left with cement nodes small enough that drilling-out is not required. And the ability to reverse out excess cement in many applications makes low pressure squeezing compatible with "thru-tubing" techniquesY6 SQUEEZE TECHNIQUES Squeeze cementing in permanent and tubingless completions requires some special precautions but basic techniques are similar to those used in conventional wells. And, for the most part, only low pressure squeeze jobs are attempted. A permanent completion is one in which tubing and wellhead remain in place during life of the well. Squeeze cementing in these wells can be performed with concentric small diameter tubing. Thru-tubing tools such as inflatable bridge plugs and packers have been developed to be run on wireline or small diameter tubing strings to permit conventional, small scale squeeze cementing operations. Squeezing through small concentric tubing uses very small slurry volumes which are susceptible to contamination by fluids in the casing and in the tubing-tubing annulus. Therefore it is particularly important to maintain accurate volume control of all fluids pumped into the well to assure proper slurry placement.
The hesitation squeeze is a subclassification of squeeze cementing that can be used in either high or low pressure applications. The principal aspect of the technique is alternate pumping and hesitation (not pumping). The hesitation is to encourage cement filter cake buildup. Hesitation procedures are much more of an art than a science, as hesitation time and pressure change during pumping and waiting are observed, and varied, based on experience. The alternating of pumping and hesitation are continued until the desired final squeeze pressure is obtained, 171 Fig. 73. The Bradenhead squeeze technique normally is used on low pressure formations. Usually the interval to be squeezed is at or near the bottom of the well. The general procedure, as illustrated in Fig. 74, includes
63
BLED PRESSURE TESTED
Ci5 2,000
0ur
BACKFLOW
!5 1,600 fd g: 1,200 w () 800 II: ::> rn 400 0
0
20
40
60 TIME, MINS.
Fig. 73-Example of hesitation squeeze technique shows alternate pumping and hesitation to allow cement filter cake formation and gradual buildup to desired squeeze pressure (after Beach et al).'" these steps: Circulate cement across zone to be squeezed; pull drill pipe (or tubing) above the perforations; close blowout preventors (or shut off flow from the annulus) and apply pressure to drill pipe or work string to force slurry to dehydrate against the formation; reverse out excess cement in the work string and casing, or let cement set, and drill out as required. Squeeze pressure is limited by casing string and wellhead burst strength, so the Bradenhead technique is normally used with a low pressure squeeze. It is not a precise cement placement technique and is not generally recommended when there are several open intervals and onl} one is to be squeezed, or where casing is not pressure tight above the zone to be squeezed.
Packer squeeze techniques permit precise slurry placement and isolate high pressure from casing and wellhead while high squeeze pressures are applied downhole. A packer squeeze can be conducted with either drillable or retrievable squeeze packers. Wellbore fluid below the packer is usually displaced through perforations ahead of the cement when this method is used. Dirty fluid may block flow of cement to a portion of any exposed permeability. In the past, main advantages of a drillable packer or retainer, over a retrievable packer, were that it prevented backflow and disruption of the filter cake and provided the ability to isolate perforations from circulation pressures above the packer. With new technology, these capabilities are available with some retrievable cement retainers, and they can be of particular -advantagewhen it is necessaryto remove the packer from the wellbore after squeezing. Retrievable packers can be set and released repeatedly on a single trip, as may be required to locate holes in the casing. When retrievable packers are released, differential pressure from the formation must be controlled to prevent back-flow and cement filter cake disturbance. Generally the retrievable packer is less expensive to run; and less rig time is required if cement is to be drilled out. Many accessories have been developed for use with the retrievable squeeze packer, such as retrievable bridge plugs that can be run below the squeeze packer and set at any point below the packer. The retrievable bridge plug will hold pressure from either above or below.
64
Although this isolation technique is most always required for high pressure squeeze jobs it can be effectively used on low pressure squeezes where accurate cement placement is desired. And, with a low pressure squeeze, it is possible to run and retrieve the bridge plug on the same trip with the retrievable squeeze packer. It is also possible to squeeze multiple zones on the same trip with this equipment. However, as mentioned earlier, differential pressure between casing and formation must be controlled to prevent displacement of unset cement filter cake. Drillable packers can be obtained with either of two valve systems. The "poppet" type back pressure valve will prevent back-flow only. The "two-way" valve will retain pressure from either direction and closes when drill pipe is pulled above the packer. The two-way valve system makes it possible to reverse circulate any excess cement from the drill pipe without exerting pressure below the packer. Drillable packers can be set on tubing or drill pipe, and by electric (logging) line. The choice between drillable or retrievable packers is primarily dependent on well conditions and squeeze technique. Details on specific capabilities of either type should be obtained from the service company or manufacturer (supplier) . Packer location should be carefully considered and may vary depending on the type job. If set too far above
'I
SPOT CEMENT
APPLY SQUEEZE PRESSURE
REVERSE CIRCULATE
Fig. 74-Schematic of Bradenhead squeeze technique normally used on low pressure formations. Cement is circulated into place down drill pipe (left), then wellhead, or BOP, is closed (center) and squeeze pressure is applied. Reverse circulating through perforations (right) removes excess cement, or plug can be drilled out.
WORLD OIL
1977
perforations or holes to be squeezed, excessive volumes of fluid-either workover fluids or mud-must be displaced into the formation ahead of the cement, or the slurry may channel through the mud, Fig. 75. Conversely, a packer set too close to perforations or holes could become stuck if pressure on the outside of the casing is transmitted above the packer and causes the casing to collapse. It is desirable to test and then maintain some pressure on the casing annulus above the packer. Observation of this annulus pressure can be effectively used as a check for leaks in the squeeze string, packer or casing. Annulus pressure can also be used to prevent collapse pressures from developing during high pressure jobs. Usually, the packer should be set 30-60 feet from perforations. If corrosion holes or split pipe are being squeezed, more space is recommended. Final squeeze pressure. Thirty (or more) years ago when squeeze cementing was more art than science, high final squeeze pressure was one primary indicator used to measure success. However, high final pressure may occur because dehydrated cement has bridged-off the casing or perforations. And mud cake filled perforations are also capable of withstanding high differential pressure, particularly in the direction of the formation. Thus high final squeeze pressures can be achieved where the squeeze is unsuccessful. Job evaluation. Proof of a successful squeeze is the withstanding of differential pressure between casing and formation after the well is returned to operation, either production or injection. However, it is usually desirable to test the squeeze job before removing the work over or drilling rig. Differential into the wellbore may be obtained by swabbing or displacing workover fluid with field crude. In some production wells it may be impractical to unload the wellbore without returning the well to production. In these cases a positive pressure test that does not exceed formation fracture pressure should be conducted after cement has set and, if required, after drillout. Even though it is not conclusive, pressure testing can be relatively quick and inexpensive to perform. It may detect a job failure, and, in most cases, less effort and expense are required to repeat the squeeze operation at that time. Procedures for evaluating cement jobs will be discussed more fully in the next article. In squeeze jobs where cement is to be drilled out, an indication of success is the way the cement drills. If it drills hard all the way, results may be good. However, soft spots or voids usually indicate an unsuccessful job.161 Remedial squeeze cementing techniques and technology provide a wide variety of "cures" for problems related to fluid movement behind the casing and/or in the wellbore. However, prevention-where possible-is a more effective, less expensive solution than squeeze cementing. Squeeze cementing is a remedial tool. It should not be used as a planned supplement to primary cementing. For example, careful design and execution of primary cementing is a much better way to get zone isolation than relying on high-pressure "block squeezing" above and below the pay. As mentioned, high pressure block squeezing may actually aggravate communication between zones.
Coming next month: Defining the problem to be "cured" WORLD OIL
1977
CASING PACKER
CEMENT CHANNELLED THRU MUD MUD
Fig. 75-Packer location is important. In this example, packer is set too high allowing cement slurry to be contaminated as it channels through mud to reach perforations or holes (after Shryock and Slagle).'68
by squeeze cementing is likely the most important rule of preparation. Many diagnostic tools and evaluation procedures that can be used to gain an understanding of downhole conditions before and after squeezing, or after primary cementing, are discussed in the concluding article, along with some recent cementing innovations.
LITERATURE CITED 'M Parsons, C. P., "Plug-back Ce1l1enting Methods." AIME Trans. Vol. 118 (1936). . ,.. Goins, W. C., Jr., "Open hole plug-back Operations," Oil Well Cement,ng Practices in tne U.S., API, 1'959. ,.. Mont/5omery, P. C. and Smith, D. K., "Oil Well Cementing Practices and Mater.als," Petro Engr., May_and June, 1'971. '" Fischer, J. S., Wadder, F. V. and McGuirel,. J. A., "hn.proving Production with Electrical Workover System," Paper SrE 24114,1969. ... Beach, H. J. and Goins, W. C., Jr., "A Method of Protecting Cements Against the Harmful Effects of Mud Contamination." AIME Petro Trans. Vol. 210, 1957. ". Morgan, B. E. and Dumbauld, G. K., "Use of Activated Charcoal in Cement to Combat Effect. of Contamination by DrilIing Muds." 160Banister J. A., "Methods and Materials for Placin Cement Plugs in Open Holes," Presented at the National Interstate Oi Compact Commission's Convention, Yellowstone Wyo., June 11957. '0' Murphyl,. W. C., "Squeeze Cemenunj! Requires Careful Execution for Proper Kemedial Work," Oil & Gas Journal, February 1976. '0' Buster, J. L., "Cementing Multiple Tubingless Completions," API Drillinll and Production Practice, 1965, pp. 15-23. .03Willingham, J. E., "Experience with 2-%" Casing in the West TexasNew Mexico Area," API Drilling and Production Practices, 1963, PI'. 64-71. 164Scott, R. W., "Small Diameter Well Completions," Engineering Practices Manual No.4, Reprinted from World Oil, 1963. ,.. Childers, M. A., "Ptim"ry Cementing of Multiple Casing," Transactions of AIME, Volume 243, 1968. '00 Clark, C. R. and Jenkins, R. G., "Cementing Practices for Tubin!!less Completions" SPE Paper 4609 Presented at the 48 Annual Fall MeeUng, Las Vegas, Sept. 30-0ct. 3, \973. 16'Holley, J. A., "Field Proven Techniques Improve Cementing Success," World 0,1 August 1976, PJI. 31'-33. ,.. Shryock, S. H. & Slagle, K. A., "Problems Related to Squeeze Cementing," /PT, August 1968. 169Torr~y, P. D., "Pr~Kress in Squeeze Cementing Application and Technique" Oil Weekly, July 29, 1940. .. 110Hook, F. E., and Ernst, E. A., "The Effect of Low-Water-Loss Additives, Squeeze Pressure and Formation Permeability on the Dehydration Rate of a Squeeze Cementing Slurry," Paper SPE 2455. Presented at the SPE Rocliy Mountain Regional Meeting, Denver, May 25-27, 1969. m Beach, H. J., O'Brien, T. B. & Goi~1 W. C' J!;..o "Controlled Filtration Rate Improves Cement Squeezing," world Oi,I May, 1961. m Binkley, G. W., Dumbauld, G. K. & Collins, R. E., "Factors Affecting the Rate of Deposition of Cement in Unfractured Perforations During S~ueeze Cementing Operations," Paper SPE 891'-G, 1957. '" Rike, J. L:t "Obtaining Successful Squeeze-Cementing Results," Paper SPE 4608, 1~73 m Carter, L. G. et al., "Remedial Cementing of Plugged Perforations," Paper SPE 759, 1963. 116Morgan, B. E. & Dumbauld, G. K.; "Bentonite Cements Proving Successful in Permanent-Type Squeeze O{)erations." 116Huber, T. A., Tausch, G. H. & DublIn, J. R. III~ "A Simplified Cementing Technique for Recompletion OperatIOns." AIME Transactions, Vol. WI, 1954. '" Harris F. and Carter, G.~ "Effectiveness of Chemical Washes Ahead of Squeeze Cementing," API raper 85'1-37-H, 1963. .
y
65
Cementing oil and gas wells Part 8-Methods for evaluating primary cementing effectiveness plus a wrapup of several new tools to improve completion operations
60
u.. o 40
George o. Suman, Jr., President, and Richard C. Ellis, Pro j ec t Engineer, Completion Technology Co., Houston 10-second summary Basic principles of temperature logging. bond logging and various tests for proving fluid shut-off by primary cementing are described, along with three new tools for completion, through-tubing work and whipstock installation. THIS CONCLUDINGarticle discusses several methods
of
evaluating the effectiveness of a primary cement job, or a remedial squeeze. The techniques include logging methods-to determine factors such as cement height, thickness, bonding or possible mud channeling-and various positive performance tests such as pressure tests, perforating and bailing, and production and/or production logging tests, to prove whether the job accomplished its intended purpose. Also discussed are several recently introduced downhole tools that are closely associated with cementing operations. These include: ~ The new Pack/Perf Completion vides positive isolation and formation the perforated interval
system that prosupport through
~ A new through-tubing, inflatable bridge plug that can simplify plug back operations in casing, below the tubing string, and ~ A permanent packer arrangement for positively anchoring a whipstock tool. The system can cut costs and eliminate cement plug placement problems, in this application. 66
20
2
3
CEMENT SHEATH THICK., IN.
Fig. 76-Lab tests of various cement thicknesses with InsulatIng and non-insulating material simulating surrounding formation Indicate that temperature rise Inside casing from setting cement can vary significantly with rock thermal dlffusivity properties (after Gretener).180
EVALUATION TECHNIQUES Evaluation of primary cementing is usually based on one of the following basic failure definitions: Cement failed to fill the casing-borehole annulus above the minimum acceptable cement height; it failed to provide a seal at the casing shoe (or at the top of a liner), or it failed to provide effective isolation of the zones of interest. When any of these failures are detected, squeeze cementing remedial operations are usually required. A number of evaluation techniques are available, including: Temperature surveys; radioactive logs; pressure tests; acoustical cement bond logs, and production testing and production logging. Temperature surveys are used to detect maximum height of cement in the casing-wellbore annulus.178.119 Reasonably accurate in this application, such surveys cannot determine cement quality, or effectiveness in preventing vertical fluid migration. The method consists of running a recording thermometer in the casing following the cementing operation. Setting cement generates "heat of hydration" which in-
WORLDOIL 1977
CEMENTTOP ENLARGED HOLE SECTION
.)
:I:
\ \
....
n., w 0
I
I
I
II
)
\ \ \ \ \ \ \ \ I
,
,,,
A
B
-
TEMPERATURE
C
Fig. 77-ldealized temperature log in homogeneous lithology environment. Curve C compared to Curve B illustrates effect of enlarged borehole with corresponding increased cement thickness (after Folmar).179 240
200 11. o
160
Ii ~ W I-
120
,--12,000
f
80~
4,000 FT TEST
o
2
___ 3
FT TEST
SLURRY TEMP. APPARATUS TEMP. 4
5
6
TIME, HOURS
Fig. 78-Cement temperaturedevelopmentwith time as a function of well depth is indicated by lab results in a simulated wellbore apparatus preheated to temperatures of various depth levels. Tests show 800 F slurry first cools fluid inside casing, then maximum temperature develops several hours after placement. Temperature rise is greater in higher temperature environment (after Farris).'" creases the temperature of adjacent fluid in the casing by several degrees. Maximum temperature anomalies may be expected to range from 10-40° F, Fig. 76.180 The magnitude of the anomaly will depend on thickness (or mass) of cemen t behind the casing, as well as the thermal diffusivity of surrounding formation. Where lithology is fairly uniform, the temperature log will indicate relative thickness of cement behind casing,179 Fig. 77. Caliper surveys can be particularly helpful in analyzing the temperature survey. If a hot area is noted where there is no hole enlargement, cement has invaded the formation through fractures or a thief zone. If the indicated cement top is higher than calculated, cement channeling should be suspected. To locate the cement top, the temperature survey should begin either at the surface or at least 1,000 feet WORLD OIL
1977
above the expected top. It is desirable to run the survey at 50 F per inch sensitivity under normal conditions. And well conditions must remain static from the time the plug is bumped until the survey is completed. Caution should be observed when mixed lithologies (sand, shale, limestone, dolomite, salt, etc.) are present because it is possible to misinterpret.a lithology change as a cement top. In these areas it is advisable to run a base log prior to running casing, to avoid possible erroneous interpretations. The rate at which temperature changes depends on temperature to which the cement is exposed. This is usually a function of depth of the cement job, Fig. 78.181 Peak temperatures often occur 4-12 hours after start of mixing operations but remain elevated for more than 24 hours, as shown in Fig. 79. Therefore, temperature surveys normally should be run between 8 and 24 hours after cement is mixed. Because these surveys are only applicable for this short period after cementing, they, of course, have no application in old wells. There are conditions in some areas where extremely high well temperatures override the temperature increase of the hydrating cement.182 If the cement top is between casing strings, the temperature will be greater than, but parallel to, the geothermal gradient. In wells in which particularly heavy or viscous drilling fluids are used, special cement displacing fluids may have to be used to permit running of the survey. Radioactive surveys. Addition of radioactive tracer material to the lead portion of the cement slurry provides a positive indicator of the cement top. Either long or short half-life material can be used. Carnolite has a half-life of approximately 1,700 years, and permanently affects natural gamma-ray emissions near its location in the well. Several radioactive materials that can be used as tracers have half-lives of 8-80 days. Principal disadvantages of radioactive survey techniques for cement height determination are: Special health precautions; interference with natural radioactive surveys, and high costS.178 Pressure,
inflow
tests.
Pressure
tests are conducted
210
2,000
VI
200 L
1,800
PRESS.RELIEVED
11. 0
a: ::?E W ....
190 180
1,600
1,400
b'"
170
Ci.i 11.
cri (f)
w II:
. 1,200
PRESS. 160
11.
1,000
150
800 0
4
8
12
16
20
24
TIME, HOURSFROM STARTINGTO MIX
Fig. 79-Temperature and pressure effects within fluid filled casing shut in immediately after cementing. Note maximum temperature buildup 8-12 hours after mixing. Temperature remains elevated for several hours (after Farris).'" 67
REVERSE CIRCULATING
DRILL STEM REVERSE CIRCULATING
HYDRAULIC MULTIPLE SHUT-IN VALVE
SUB.
ROTATING SHUT-IN VALVE
SUB.
n ]
] ..~.
j
HYDRAULIC VALVE
INSIDE RECORDER CARRIER JARS SAFETY JOINT PACKER INFLATION PUMP
The WSO procedure can be as simple as bailing fluid from the casing and checking for fluid rise-after casing has been perforated or drilled out. However, perforating and testing is more commonly conducted with combination tools that can be run on tubing or wireline. A WSO test can give positive indications of communication problems, or lack thereof, prior to final completion. However, WSO perforations must enter the mud channel, if one is present. And a small channel can be missed with zero-degree gun phasing. The tighter the phasing, the lower the chances of missing a channel.
to verify integrity of the casing following primary cement jobs. And specific procedures are specified by government regulations in most locations. The casing pressure test is conducted after cement has set but prior to drilling out the cement shoe. These tests are not an indication of cement effectiveness.
Combination of a mechanically fired perforating device and a testing tool makes it possible to perforate and test on a single trip with tubing or drill pipe.183 This test is conducted by perforating an impermeable zone above or below the zone of interest, setting the packer and opening the tester valve. A minimum cushion, fluid or gas, is placed inside the test string. In some locations regulations specify the maximum amount of cushion. Inside and outside recording pressure instruments are also included as an integral part of most testing tools, Fig. 80. The tester is usually left open for a:bout an hour. If strong entry is indicated by a heavy "blow" at the surface, the tester may be pulled sooner. The amount and type of fluid inside the test string can be checked by reverse circulating the sample to surface or by retention in the string and later recovery. Pressure charts are checked to confirm that the tester was open and exposed to cushion/formation pressure, to verify a good test. Where there is a need for very accurate location of WSO holes, a wireline perforator can be used with a collar locator and/or gamma ray log for correlation. After perforating, a conventional tester is run on tubing and the test is conducted, as with the combination tool. Stra.ddle packers can be used to test more than one set of WSO holes above and below zones of interest. With a bottom packer added to the test assembly, each set of WSO holes can be isolated and tested, Fig. 80. Wireline perforating and testing tools are available for obtaining small fluid samples following selective perforating. These tools are primarily used to perforate through to the zone of interest and obtain a sealed reservoir fluid sample that could be suitable for PVT analysis. The size of the sample chamber limits the application of this type equipment.
In some locations, i.e., California, regulations require that the casing be perforated and tested by either bailing or inflow evaluation tests, called water shut-off (WSO) tests. In California the WSO tests provide assurance that a cement seal of the annulus exists, to protect shallower freshwater reservoirs from brine and/or hydrocarbon contamination. This procedure of perforating and checking rate and content of inflow, if any, has been used to verify a cement seal above and/or below hydrocarbon producing zones in many areas. The advantage of this technique is that if a failure is indicated, a cement squeeze of the WSO holes will be placed opposite a non-productive formation, rather than opposite the zone of interest. Also, inflow likely will purge mud from the perforations, a desired preparation for low pressure squeeze jobs.
After drilling out. Where additional drilling is to be conducted and when the casing is cemented in an impermeable formation, the casing shoe can be drilled out and the casing seat inflow tested. The amount of open hole to be drilled .below casing is specified by law, in some locations, but is usually 5-10 feet. Tests can be made with a conventional tester set near bottom. The testing procedures are the same as those used with the perforating and testing program. A pressure test can also be conducted after drilling out the casing shoe and 5-10 feet of open hole. Two objectives of this procedure are: To test effectiveness of the cement seal at the casing shoe; and to determine formation strength (fracture gradient) at the shoe. One indication of cement seal failure at the casing
INSIDE RECORDER CARRIER
HYDRAULIC
;1
SCREEN SUB.
TOP PACKER
JARS ]
TEST PORTS
SAFETY JOINT
OUTSIDE RECORDER CARRIER PACKER
SPACING
PERFORATED ANCHOR
BOTTOM PACKER
OUTSIDE RECORDER CARRIER ANCHOR SHOE SINGLE COMPRESSION PACKER
t
BELLY SPRING
INFLATABLE STRADDLE PACKERS
Fig. SO-Two types of drill stem test tools used to check pos-
sible fluid entry from a cement job test. Single packer type (left) must be set above single test point. Inflatable straddle packer tool (right) can test more than one interval (courtesy Lynes Inc.).
68
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1977
shoe is loss of drilling fluid at pressure less than calculated fracture pressure. When this occurs it usually indicates channeling during cement displacement, and steps should be taken to squeeze cement the shoe. It is recommended that estimated surface test pres-
sure (PST) required to fracture the formation prior to the test, using the equation:
be checked
PST = FG X D - 0.052p X D = Surface test pressure, psi
Where: PST
FG = Fracture gradient, psi/ft. D = Depth, ft. p = Mud density, ppg. A. FREE PIPE
B. GOOD BOND TO PIPE AND FORMATION
I C)I ~I !;(I C)I I I
o a: w N W ::E
i=
This surface test pressure must also be less than the pressure rating of equipment, i.e. wellhead, BOP, casing, etc. H the drilling fluid has low mud weight and high fluid loss, rate of pressure bleed-off may be considerable. In some instances, it may be difficult to distinguish between fluid loss to permeability, poor cementation and/or formation yield (fracturing).
C.
GOOD BOND TO PIPE, NO BOND TO FORMATION
D. DECENTRALIZED PIPE, ONE SIDE NOT BONDED
TIME_
Fig. 81-Examples of acoustic signals actually received in test wells under various cementing conditions (after Walker).'''
GAMMA
AMPLITUDE
..
API GAMMA RAY UNITS 10 110
PIPE BOND
MICRO-SEISMOGRAM
.!_0!l~~I!<2.N_~q,N'p_ 200
LOG
1,200
o
~o
o
Co> o o
Fig. 82-Example
of a cement bond log display of a section of well-bonded casing shows typical data included on field log. Amplitude-time display (right) indicates weak pipe amplitude signal (grey tone left half) and strong formation signal (black line right half) comparable to signal B in Fig. 81 (courtesy Welex).
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1977
Acoustical cement bond logging in use since 1960, provides an evaluation of the cement column behind casing. The cement bond log (CBL) combined with an acoustic signature log (MSG, VDL, XV, etc.) is a log in which both time of arrival and amplitude of vibrations are used to evaluate bonding conditions. Sonic signals are transmitted to a receiver that is acoustically isolated within a combination tool. In traversing through casing, signal amplitude is attem.\ated to a varying degree depending on material outside the casing. Attenuation effect will be greater if that material is solid and bonded to the casing. Signal amplitude is converted to electronic signals and varies inversely with degree of attenuation. Thus a high amplitude casing signal is indicative of no bond between cement and casing, Fig. 81 (A). When cement is firmly bonded to casing and formation, there is a low casing signal and the signal received is characteristic of formation behind pipe, Fig. 81 (B). When cement is bonded to pipe bu t not formation, both casing and formation signals have low amplitude, Fig. 81 (C). When casing is resting against the borehole, channeling commonly occurs, preventing cement from surrounding the casing. Thus casing is free on part of its circumference and formation-cement-casing coupling exists around the balance. Then both casing and formation signal are present as shown in Fig. 81 (D). It is important to receive more than just the casing signal. Acoustic signals travel through fluid in the wellbore, casing, cement and/or annular fluids and formation. The casing and formation signals are of primary interest. Additional details of CBL techniques, technology and procedures are available in the literature.184-196 eBL presentations.
Acoustic signals in a cased borehole consist of all arrivals along any coupled path between transmitter and receiver. The time and amplitude of the combined signal from the various paths are such that all information cannot be presented adequately by a normal logging curve. Thus a CBL usually includes an amplitude curve that measures a specific time segment of the acoustic signal and one or more of the following: . Transit time of the first acoustic signal that exceeds a predetermined amplitude 69
. Amplitude of the formation signal, and . A variable intensity recording where dark and light streaks represent positive and negative half cycles of the acoustic signal, or . An acoustic scope picture-XY presentation.
include a gamma ray curve and a casing collar log, Fig. 82. Though not directly related to acoustic properties measured by CBL, this information has proven helpful in CBL interpretation.
Additional measurements frequently included on CBLs
Interpretation. Validity of CBL interpretation is a controversial issue. There are no industry standards for tools or procedures. Inadequate information on CBL headings, miscalibration of tools, lack of effective tool centering in the casing and/or poor running procedures have resulted in misleading interpretations. Interpretation of a specific CBL depends on how and what portion of the acoustic signal is measured and recorded. Factors that significantly affect tool response include: Acoustic frequency of tool; electronic control that determines the acoustic signal segment measured (Gating systems and bias settings); spacing between transmitter and receiver; tool calibration; centralization, and logging speed. Here are other factors that can introduce errors in
1.5
en I-I o > ui c ::) I::::;
Q. ::E
CBL interpretation: . Extent of cement set (hardening) affects sonic signal velocity and amplitude. During the setting process, gel which forms around the cement particles is apparently an excellent absorber of acoustical energy. As cement hardens, acoustic transmissibility increases significantly and the casing signal is dampened out. Thus it is best to run CBLs at least 24-36 hours after the cement job is completed or when compressive strength of cement reaches 1,000 psi.
o o
3
2 CEMENT SHEATH THICKNESS, INCHES
Fig. 83-Effect of cement sheath thickness on pipe amplitude signal (with pipe bonding only). With less than ~-inch, amplitude increase tends to indicate free pipe. 100
. Cement composition also affects acoustic transmission. If a high degree of sensitivity is applied where low-density cementing materials have been used, poor bond may be indicated although good bonding actually exists. Tests in dril1ed holes with casing cemented with API Class A cement, indicated that small sections void of cement could be located only by using high sensitivity. Therefore, voids or channels may not always be indicated on CBLs unless proper sensitivity selection-with respect to cement composition-is used.1" . Cement sheath thickness may vary, causing changes in attenuation rate. Lab tests indicate that a thickness of ~-inch or more is required to achieve full attenuation, Fig. 83. Thus, casing should be sized to provide a minimum of ~-inch clearance in the drilIed hole, with adequate centralization. Cement thickness can be critical in certain liner completions where thickness is less than ~-inch.
> ::!: ui C :J I::i Q. ::!:
. Cement compressive strength and percent of casing circumference bonded affects CBL amplitude, Fig. 84. It is not possible to determine the difference between a job in which cement strength is lower than anticipated, and a job in which cement strength is as estimated but small mud channels exist.18O Vertical zone isolation does not exist in the latter case.
10
. A microannulus is a very small gap between casing and cement. This gap will affect a CBL. However, the presence of a microannulus normally does not prevent isolation between zones and it usually tends to "heal" with time.
51,h" CSG., 0.3" THICK.
1.0
0.2
_
o
20
40
% CIRCUMFERENCE
60
80
100
BONDED
Fig. 84-Relation of cement bond log pipe amplitude to cement compressive strength and percent circumference bonded. Example: 500-psi cement with 80% bonded shows same signal as 4,OOO-psicement with 40% bonded (after Schlumberger). 70
A microannulus can be caused by: Shutting in the casing and allowing pressure on the casing to increase due to temperature rise; thermal expansion of the casing while cement sets and subsequent temperature reduction; contaminants on the external surface of the casing such as mill varnish, grease, oil-wetting, etc.; and by displacing drilling mud with lighter-weight completion fluid prior to running the CBL. Where a microannulus is indicated by logging, it is recommended that a short overlap CBL be run under pressure, opposite zones of interest. The entire CBL WORLDOIL
1977
10. Radioactive fluid injection and surveys to identify injection points and possible presence of migration channels behind casing, and 11. Noise-logging to detect behind-casing fluid movement.
As mentioned in Part 7 of this series, the most im~. portant rule of preparation for remedial cementing operations is to accurately define the downhole problemif any exists. Generally a combination of production tests and production logging procedures are required to identify and locate channels or other problems associated with lack of effective zone isolation. Verification of remedial ,workover effectiveness requires the same tests and/or other combinations of tests and logging procedures.
RUNNING POSITION
COMPLETED SYSTEM
Fig. 8S-Schematic of Pack/Perf Completion System illustrates inflatable external casing packer as primary cement is being displaced (left) and after rubber element has been filled with cement and the pay zone has been perforated (right).'o. should be run under pressure if there is a significant change in amplitude with the casing pressured. When mud channels are present, pressuring the casing will have little, if any, effect on the CBL.195 With channeling, vertical isolation does not exist and remedial squeeze cementing should be considered. Remember, a channel may only be on one side of the casing and chances of perforating into such a channel with a singlephase gun are minimal-use a 90-degree phased gun to perforate when channeling occurs. The CBL can be an important aid in estimating cement bond quality, when properly applied.195 CBL interpretation is not sinJple and straightforward as is often assumed. And detailed information on cementing and logging operations are essential for accurate interpreta:tion. Production testing, production logging. The most positive evaluation of cement effectiveness has been obtained by production testing and production logging methods, following completion operations. These methods include one or more of the techniques shown below: 197 -203 Production testing/logging techniques 1. Production tests-flow rate and content (water, oil, gas and solids, if any) 2. Inflow evaluation by determination of flow rates and con. ten t vs. surface flowing pressures 3. Comparison of 1 and/or 2 with fluid rate and content expected based on open hole logging data 4. Evaluation of historical production data and comparison between wells with common completions (production surveil. lance) 5. Pressure build-up and fall off measurements with down. hole pressure reorders 6. Inflow vs. depth measurements with downhole flowmeters 7. Flowing and/or static temperature vs. depth measurements with high resolution surface recording thermometers 8. Flowing fluid density vs. depth measurements 9. Downhole fluid samples
WORLD OIL
1977
Primary cementing has been called "The Critical Period" of drilling and completion operations. And there is universal agreement that effective primary cementing is a critical requirement for effective completions and minimal operating problems. Without zone isola:tion, subsequent stimulation, reconditioning and recompletion will be less productive and more costly, at best. And secondary recovery efforts will be much more difficult to monitor and control. Perhaps the most important primary cementing procedure is accurate and detailed documentation of the casing running and cementing operations. This information is invaluable for evaluating cement jobs-it is absolutely essential if improved procedures and equipment are to be developed.
Recommended job documentation Casing details Size, weight, grade, equipment (centralizers, scratchers, float shoes and collars, stage collars, petal baskets, etc.), inspection procedures, special handling, joint make-up tests and procedures, running speed, details of movement during cementing (if any), landing practices, etc. Cement details Volume, type and composition, density, rheology characteristics, displacement procedure (rate, use of top and bottom wiper plugs, preflush and spacer fluids including description and volume, etc.)", service company, pressure and rate charts, surface circulating temperature, anticipated set time, etc. Other details Lost circulation, premature build-up of pressure, detail of any operating problems like pump break down or delays, poor mud conditions, etc.
CEMENTING EQUIPMENT
INNOVATIONS
The Pack/Perf Completion system, developed by Completion Technology Co. and manufactured by Lynes, Inc., provides one technique for assuring a positive barrier to vertical fluid movement in the casing-wellbore annulus. And, borehole wall support is established that substantially exceeds such support obtained through conventional cementing methods. The completion consists of locating one or more inflatable external casing packers (ECPs) opposite zones to be perforated. Following conventional cementing operations, and before cement sets, the ECPs are inflated with cement. This procedure: Purges by-passed movable mud; encourages casing centralization; and mechanically dehydrates residual mud cake against the formation. Cement inside the casing is drilled out after necessary
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SMALL. DIA. TUBING
DRILlPIPE ELEMENTS
__
CASING
DEFLATED INFLATED STARTING MILL WITH PilOT
,
TOOLaD 2 "/16" WHIPSTOCK
PERMANENT PACKER MODIFIED TO RECEIVE AND lATCH WHIPSTOCK
Fig. 86-New through-tubing inflatable bridge plug can be run through 3V2-inch tubing, on macaroni string or coiled tubing, and set in casing as large as 7o/s-inch. Tool holds 700-psi differential pressure (photo courtesy Lynes, Inc.).
wac time, and cement filled ECPs are perforated to establish exclusive communication to zones of interest, Fig. 85. The need for remedial squeeze cementing for zone isolation should be eliminated. Casing will be centered in the borehole at the ECP and a unifonn cement sheath thickness will exist. Isolation packing, ball sealers, chemical diverters, etc. are frequently used to ensure that each perforation receives treating fluids. However, after improper conventional cementing, such fluids may move vertically in the annulus even though they entered individual perforations. The Pack/Perf system contacts the formation with a pressurized rubber seal, backed by non-contaminated cement, that positively blocks vertical fluid movement in the annulus. Acid, hydraulic frac fluid, chemical sand consolidation fluid and other treatments will enter the fonnations for which they are intended. Increased borehole wall support can be a significant advantage where wells are completed in weak fonnations or where the reservoir is geopressured. Such formations are particularly subject to failure if mechanical
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of new whipstock anchor offered by Baker Fig. 87-Schematic Packers. System provides positive seat without danger of disturbing tool when bit is pulled back through casing window. Permanent packer is set first in oriented position (if desired) then whipstock anchor is run on the pilot mill and stabbed into the packer. Additional set-down weight then shears mill free to begin sidetrack operation. support is not provided. Mud channels or pockets left from conventional cementing can be "drained" when the well is perforated and produced. This can remove lateral support and cause failure of the formation rock. In unconsolidated sands, lateral support can be a factor preventing initial sand movement that leads to sand control problems. This new support mechanism provides the means to establish stabilized arch sand controla method that could increase productivity at minimum cost.204,205
Through-tubing bridge plug. Lynes Inc. has recently introduced a new tool that can supplement, simplify or even eliminate certain cement plug back operations in casing (or possibly open hole) below an existing tubing string, Fig. 86. The pennanent through-tubing inflatable bridge plug device has a 2 11/16-inch aD. It can be run, on a macaroni string or coiled tubing, through 3~-inch tubing and be expanded with fluid and set inside casing, up to 7 5/8 inches. Once set, the plug is capable of withstanding up to 700 psi differential pressure. The tool can be used to bottom a cement plug or, WORLD OIL
1977
by itself, to shut-off bottom water from a perforated interval, etc. Whipstock anchor. A new system is now offered for setting an oriented, or non-oriented, whipstock on a permanent packer arrangement prior to cutting a window in casing for sidetracking operations, Fig. 87. Developed by Baker Packers, a Division of Baker International Corp., the packer and anchor assembly positively anchors the whipstock in place, preventing both rotation and vertical movement. The packer also functions as a permanent bridge plug to isolate the casing below the window. It can be run on electric line or pipe. However, if directional orientation is required, the packer, will have to be run on pipe. The system is an alternative to a cement plug placed for sidetracking operations. Generally, less rig time and lower total cost will be realized for sidetrack operations with this new innovation. And, it eliminates the potential problem of whipstock movement when the bit is pulled up through the window. Unless prevented, such movement can cause re-entry difficulties.
LITERATURE
CITED
178Teplitz, A.J. and Hasselbrock, W.E., "An Investigation of Oil Wen Cementing," API 1946 Drillin~ & Production Practices. 119Folmar, L.W., "Methods of Detecting Top of Cement Behind Casing," API-Oil Well Cementing Practices in the U.S., 1959 (Chapter 12). 18.Gretener, P.E., "Temperature Anomalies in Wells Due to Cementing of Casing," ]PT, February 1968. '8' Farris, R.F., "Method for Determining Minimum Waiting-on-Cement Time," Petroleum Technology, January 1946. '8. Kading, H.W. and Hutchins, J.S., "Temperature Surveys: The Art of Interpretation," API Drilling & Production Practices, 1969. '83Young, V.R., "Testi!'$ of Primary Cement Jobs, API-Oil Well Cementing Practices in the U.S., 1959, ChaRter 111'. 18.Anderson, W.L. and Walker, T., 'Research Predicts Improved Cement Bond Evaluations with Acoustic Logs," ]PT. November 19611. 188Winn, R.H., Anderson, ,T.O., Carter, L.G., "A Preliminary Study of Factors Influencing Cement Bond Logs," ]PT, April 1962. '86Walker, T., "Case Histories of Bond Logging," O&G], May 7, 1962. 181Riddlo;., G.A., "Acoustic Wave Propogation in Bonded and Unbonded Oil Well t.
End of series
WORLD OIL
1977
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