VIETNAM NATIONAL UNIVERSITY, HO CHIMINH CITY HO CHI MINH CITY UNIVERSITY OF TECHNOLOGY MASTER THESIS TASK Student’s name: LƯƠNG THỊ HỒNG SƠN STUDENT ID: 7140880 Date of birth: 24/12/19
OVERVIEW OF CEMENTING HPHT WELLS IN Y FIELD,
Petroleum geology and temperature of Y field, Nam Con Son Basin
The Nam Con Son Basin is situated within 6deg6’- 9deg45’ and 106deg0’ – 109deg30’E Its southern and southeastern boundaries are in the Vietnamese waters which border the neighboring countries, and its eastern, northern and western boundaries are on the Vietnamese continental shelf All geological formations in Nam Con Son Basin can be divided into two complexes of major structural elements, the basement composed of Pre-Cenozoic strata and the cover composed of Cenozoic sediments Good source rock sequences are developed in Oligocene lacustrine claystone and in Miocene fine grained clastic
Figure 1.1: Y field at Nam Con Son Basin
Figure 1.2 Play types of Nam Con Son Basin [20]
The fact that high temperature and high pressure appeared at well X, true vertical depth is 3,740 meters, bottom hole pressure (BHT) is 172degreeC and Reservoir pressure is 74MPa; and at another well X1, true vertical depth is 4,548 meters, BHT is 210degreeC and Reservoir pressure is 91MPa [8,9] are research target of this thesis
Figure 1.3 Temperature and Pressure vs True Vertical Depth in NSC Basin [7]
Figure 1.4 Matrix of High Pressure High Temperature Operation [1]
Figure 1.5 HPHT Tiers, Courtesy of Baker Hughes 2005 [1]
Figure 1.6 HPHT Tiers, Courtesy of Schlumberger, 2008 [1]
Figure 1.7 HPHT Tiers, Courtesy of Halliburton, 2012 [1]
Figure 1.8 Temperature and Pressure map at Nam Con Son Basin [19]
Figure 1.9 Pressure profile at block 04, 05 Nam Con Son Basin [19]
Figure 1.10 Temperature profile at block 04, 05 Nam Con Son Basin [19]
Information about cementing for HPHT wells in Nam Con Son Basin [19]
According to consolidated information from drilling programs and/or well information including cementing programs and cementing evaluation reports
Below is the results of the cementing process for high pressure, high temperature (HPHT) wells in the Nam Con Son basin, for the purpose of evaluating the success rate, geological and operation challenges and lessons learnt in order to propose solutions and techniques to improve the quality of future drilling and cementing for high pressure, high temperature wells in the Nam Con Son basin A number of oil companies have drilled in this area over the periods such as ONGC, BP, Shell, BG, Petrocanada and BHP…
No Well name Water depth (HPHT) (m)
Table 1.1 Wells at Nam Con Son Basin with water depth of HPHT
Nowsco, Dowell/Schlumberger, BJ Halliburton are the 4 cement service providers for the wells in Nam Con Son Basin Class G cement and some additives were used such as silicate, retarder, fluid loss additive, weighting agent… Cement density is 1.75 – 2.22s.g, bottom hole temperature is 130-155degC and apply one or two stages cementing
Block Casing TOC (m) Cement density
Table 1.2 Technical design and technology of cementing wells in block 04 & 05 Nam Con Son Basin
Table 1.2 Cementing design from service providers for wells at Nam Con Son Basin
Well name Casing Cement Slurry design
0.0 3gps+BOWC-D157/0,5gps+SF/0.35gps+
D066 35%BOWC+Micromax 45%BOWC+D144/0.05gps+D134/3.2gps+D135/0.
0.03gps+BOWC-D157/0,5gps+SF/0.35gps
35%SSA +35%BOWC+Micromax 45%BOWC+D144/0.05gps+D134/3.2gps+D135/0.
35 GPS+D080/0,5GPS+D109/0.16GPS+ HL- 25r/0.23gps
Table 1.4 Slurry Design applied for HPHT wells in Nam Con Son Basin
Complex geology in Nam Con Son basin, especially Miocene area with abnormal temperature and pressure has incurred serious failure during cementing operation
Some failures such as Cementing stuck in 13 3/8” casing, loss circulation, cement set in casing 2.097 – 2.882 m due to pressure affects cement slurry, reduce its thickening time The cement set quicker than expected and causes loss circulation or Cement failure in 7 5/8” casing, unable to displace cement to annulus so it’s set in casing at 1.743 – 4.510 m due to unable to mill out the plug and the valve was stuck [19]
CEMENT IN HIGH TEMPERATURE HIGH PRESSURE
Basic Cements
Portland cements are used for well cementing throughout the world They are manufactured by combining limestone (calcium carbonate) and clay (silicon oxides + aluminum oxides + iron oxides) in about a 2:1 ratio then heating to a temperature of 2,600degF to 3,000degF The mixture is heated to initiate chemical reactions between the limestone and clay Several products from as a result of these reactions and the combined mixture of these products is called cement clinker The cement typically encountered is in power form It is made by pulverizing and grinding the clinker
The limestone/clay reactions lead to the formation of four different products that comprise four distinct crystalline phases: alite, belite, aluminate, and ferrite The alite phase is composed primarily of tricalcium silicate (C3S) and it makes up 50-70% of typical cement clinker Belite consists of primarily of tricalcium aluminate and tetracalcium aluminoferite and typically constitute 5 to 10% and 1-15% of a clinder, respectively In addition to the four major clinker produces, gypsum can be ground with the clinker to control the rate of setting, and CaSO4, MgO, Na2O, K2O, and other oxide impurities can be present in varying quantities, depending on the composition of the raw materials (limestone and gray) Used for clinder manufacture
Each of the cement constituents participate in dry ration reactions in the present of water, but the rate of hydration can differ for each constituent For example, C3A hydrates much more rapidly than other cement components, and C2S hydrates at a much slower rate than C3S In general the relative hydration rate follows the sequence: C3A>C3S>C4AF>C2S The overall hydration rate for a cement depends on the relative quantities of each of the cement constituents The development of compressive strength is primarily dictated by the two major cement components, C3S and C2S C3S is the constituent primarily responsible for the development of early (1-28days) compressive strength, while C2S is responsible for the development of later (28+days) compressive strength The diffraction rate for a cement is also highly dependent on the cement particle size (controlled during the process of grinding the clinder) and the temperature experienced by slurry during setting It is possible to control the hydration rate, to some degree, by using accelerating and retarding additives
The hydration of cement is an exothermic process (i.e.: heat is liverated during the reactions) and each of the cement components has a characteristic heat of hydration that contributes to the overall heat of hydration depends on the relative quantities of each of the constituents in the cement The relative heat of hydration follows the sequence: C3A>C4AF>C3S>C2S Therefore, a cement with high proportion of the aluminate and ferrite phases is expected to generate a great deal of heat on hydration
In practice, however, it is more important to know the expected temperature increase within cement slurry rather than the total amount of heat liberated on hydration In general, the rise in temperature with the cement slurry with increase with increasing section thickness and increasing quantities of hydration accelerators Therefore, cementing narrow sections (e.g., slim holes) with retarded slurries should minimize the temperature increase caused by hydration Cementing wide sections with accelated slurries can require additional steps (e.g., adding pozzolaniz materials to the slurry) to prevent excessive heat up of the slurry during setting
The different classes of cement used in well cementing are as below:
The product is obtained by grading Portland cement clinker, consisting essentially of hydraulic calcium silicates which usually contain one or more forms of calcium sulfate as an interground addition At the option of the manufacture, processing additions can be sued to manufacture the cement if such materials in the amounts used meet the requirements of ASTM C 465 This product can be used when special properties are not required It is only available in ordinary (O) grade (similar to ASTM C 150, Type I)
The product is obtained by grinding Portland cement clinder, consisting essentially of hydraulic calcium silicates which usually contain one or more forms of calcium sulfate as an interground addition At the option of the manufacture, processing additions can be used to manufacture the cement of such materials in the amounts used meet the requirements of ASTM C 465 This product can be used with conditions require moderate or high sulfate resistance It is available in both moderate (MSR) and high sulfate-resistant (HSR) grades (similar to ASTM C 150, Type II)
The product is obtained by grading Portland cement clinder, consisting of hydraulic calcium sulfate as an interground addition At the option of the manufacture, processing additions can be used to manufacture the cement if such materials in the amounts used meet the requirement of ASTM C 465 This product can be used when conditions require high, early strength It is available in ordinary (O), moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) grades (similar to ASTM C 150, Type III)
The product is obtained by grading Portland cement clinder, consisting essentially of hydraulic calcium silicates which usually contain one or more forms of calcium sulfate as an inter ground addition At the option of the manufacture the cement if such materials in the amounts used meet the requirement of ASTM C 465 Further at the option of the manufacturer, suitable set-modifying agents can be interground or blended during manufacture This product can be used in conditions of moderately high temperatures and pressures It is available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) grades
The product is obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates which usually contain one or more forms of calcium sulfate as an interground addition At the option of the manufacturer, processing additions can be used to manufacture the cement if such materials in the amounts used meet the requirements of ASTM C465 Further, at the option of the manufacturer suitable set-modifying agents can be interground or blended during manufacture This product can be used in conditions of high temperatures and pressures It is available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) grades
The product is obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates which usually contain one or more forms of calcium sulfate as an interground addition At the option of the manufacturer, processing additions can be used to manufacture the cement if such materials in the amounts used meet the requirements of ASTM C 465 Further, at the option of the manufacturer, suitable set-modifying agents can be interground or blended during manufacture This product can be used in conditions of extremely high temperatures and pressures It is available in moderate sulfate-resistant and high sulfate-resistant grade
The product is obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates which usually contain one or more forms of calcium sulfate as an interground addition Only calcium sulfate, water, or both can be interground or blended with clinker during the manufacture of Class G well cement
This product can be used as a basic well cement It is available in moderate sulfate- resistant and high sulfate-resistant grades
The product is obtained by gridding Portland cement clinder, consisting essentially of Hydraulic calcium silicates which usually contain one or more forms of calcium sulfate as an interground addition Only calcium silicates which usually contain one or more forms of calcium sulfate as an interground addition Only calcium sulfate, water, or both can be interground or blended with the clinder during the manufacture of Class H well cement This product can be used as a basic well cement It is available in moderate sulfate-resistant and high sulfate-resistant grades
In the United States, the primary cements used for well cementing are Class A, B, C, G and H In other countries, the primary cement used in the well cementing is Class A or G
In most other countries of the world outside US, service company use the API nomenclature for well cement descriptions as customer normally wants a cement that meets all API specifications, the cement manufacturer will furnish a quality control sheet providing the testing information for that batch of cement For the specification testing purposes, the water requirements for the different classes of cement primarily used in well cementing are detailed in Table 2.1
Water requirements for Different Classes of Cement
Cement Classes Water % of Weight of
Table 2.1 Water Requirements for Different Classes of Cement
For basic cementing, the high yield (in terms of cubic meter of slurry per sack of cement) makes cement the lowest cost slurry we can mize at typical density required for riserless cementing
High Temperature Cements
Cements for high-pressure/high-temperature applications should be good quality API Class G or H cements These cements are obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates that usually contain one or more forms of calcium sulfate as an interground addition Only calcium sulfate, water, or both can be interground or blended with clinker during the manufacture of Class G or H well cement This product can be used as a basic well cement It is available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) grades Portland cement is manufactured by combining limestone (calcium carbonate) and clay (silicon oxides + aluminum oxides + iron oxides) in a 2:1 ratio and then heating the mixture to a temperature of 2,600°F to 3,000°F The mixture is heated to initiate chemical reactions, and the combined mixture of these products is called cement clinker Cement is made by pulverizing and grinding the clinker
Elevated temperatures and pressures can greatly accelerate the hydration rates or thickening and setting times of the cement Certain chemical parameters become critical in the performance of the cement at elevated temperatures The levels of aluminate (C3A) should be fairly low (generally below API requirements) since C3A hydrates rapidly The free lime should be kept below 0.5% (0.3% or less is even better in most cases) Free lime or calcium oxide is the most rapidly hydrating component in cement and can be responsible for premature gelation and ineffective retarder responses Gypsum levels normally should be around 3to 4%, and bass onite (plaster of paris form of CaSO4) should be less than 1%because it may cause gelation
Tricalcium silicate (C3S) should be in the medium range as recommended by API Specification 10A Hydration of the C3S is the main reason for early thickening and strength development of the hydrating cement Dicalcium silicate (C2S) is responsible for the final stage of cement hydration and gives the cement its final
“kick” in high strength development API does not require C2S, but good high- strength cements should have 15 to20% C2S for optimum strength development
The grind or fineness of the cement is important and can become a critical factor in the performance of the cement as it hydrates under elevated temperatures and pressures General data for fineness usually is given as a measurement of specific surface or surface area These numbers are good guidelines but do not always reveal the true nature of the cement grind A particle size distribution analysis or a sieve analysis can determine the actual amount of fines and coarse particles in the cement
Excessive fines may cause premature thickening, water requirement changes, etc
Excessive coarse particles may cause the opposite effect Sometimes these two parameters may “average out,” and the fineness data may look normal Blaine fineness values normally fall around 2,700 to 3,300cm2/g Sieve analysis of suitable Class G or H are generally 78 to 85% passing through a 325 mesh sieve Slurry consistency from batch to batch can minimize lab time, physical testing, and design changes Cement suppliers should be encouraged to develop and produce good quality cement and to maintain consistent quality
Temperature in the range of 400degF to 500degF for deep oil and gas wells are not uncommon Geothermal wells with bottom hole temperatures ranging from 400degF to 750degF producing flashing brine are frequently encountered Cement slurries used in these operations should remain competent at high temperatures and pressures for extended periods of time Set cement exposed to temperatures higher than 230degF gradually increase in permeability and decrease in strength Strength retrogression can eventually produce inadequate pipe support, and increased permeability can result in the loss of zonal isolation
When Portland cement is mixed with water, tricalcium silicate (C3S) and dicalcium silicate (C2S) hydrate to form calcium silicate hydrate (C-S-H) gel and hydrated lime
(Ca(OH)2)2 At temperatures higher than 230degF, C-S-H gel converts to α- dicalcium silicate hydrate (α-C2SH) Conversion to the α-C2SH phase results in the loss of compressive strength and an increase in permeability Conversion of C-S-H gel to α-C2SH at 230degF and higher can be prevented by adding crystalline silica (fine sand, SSA-1, or coarse sand, SSA-2) The concentration of crystalline silica varies from 35 to 70%, depending on bottom hole static temperature and water content of the slurry Recent work has shown silica flour (SSA-1) provides maximum benefit for temperatures ranging from 230° to 440°F For conditions where density is critical, coarse grade sand (SSA-2) is preferred for a densified slurry The reaction between SSA-2 and cement takes place slower than the reaction between SSA-1 and cement.4The conversion to a-CaSH at 230°F can be pre-vented by adding either SSA- 1 or SSA-2 AddingSSA-1 or SSA-2 increases the molar ratio of CaO/SiO2 to one or less, resulting in crystalline to bermorite formation Formation of the to bermorite phase prevents strength retrogression and permeability increase At temperatures higher than 300°F, to bermorite converts primarily to xonolite At 480°F, truscotlite begins to appear Above 750°F, xonolite and truscotlite reach the limit of their stability At higher temperatures, crystalline phase’s xonolite and truscotlite dehydrate, resulting in the breakdown of the set cement To achieve maximum strength and minimum permeability at high temperatures, a CaO/SiO2 ratio of one or less should be maintained
Other components of cement - Cement Additives
Cement additives have been developed to allow the use of Portland cement in many different oil and gas well applications Cement additive development has been ongoing for decades These additives make obtaining required performance properties relatively easy
Typical additive classifications are listed below:
Accelerators are used to shorten the set time of cement slurries or accelerate the cement setting They do not increase the ultimate compressive strength of cement but do increase the rate of strength development They also shorten the thickening time
Accelerators are used at low temperatures to reduce time waiting on cement (WOC)
The most common accelerator is calcium chloride, commonly used at 3% or less by weight of cement
Retarders are used to decrease the set time of cement slurries or to retard the cement setting They do not decrease the ultimate compressive strength of cement but do slow the rate of strength development They also lengthen the thickening time Retarders are used at higher temperatures to allow time for placement of the liquid slurry The most common retarders are natural lignosulfonates and sugars Lignosulfonates are normally used at circulating temperatures up to 200°F Sugar compounds are normally used at circulating temperatures from 200 to 350°F The newest retarders are made from various synthetic compounds
Fluid-loss additives – permeability plugging additives
Fluid-loss additives reduce the rate at which water from cement is forced into permeable formations when a positive differential pressure exits into the permeable formation Fluid-loss additives are normally polymers such as cellulose, polyvinyl alcohol, polyalkanolamines, polymers of polyacrylamides, and liquid latex such as styrene butadiene latex Most fluid-loss additives increase the slurry viscosity, although some retard it to some degree
Extenders – water adsorbing or lightweight additives
Extenders are used to reduce the density or cost of the slurry Extenders are a broad class of materials that reduce the density or the cost of the slurry Water is the cheapest material that can be added to cement Normally a sack of cement (94 lb) will give about 1 ft3 of slurry Adding extra water can increase the volume to 3.0 ft3/sk The problem is that the slurry will become too thin and the cement will settle and have free water To prevent this problem, extenders (thickeners) such as bentonite or sodium silicate are added The disadvantage of adding the extra water is that the strength of the set cement is lessened by the dilution If low density and higher strength are required, the density of the slurry can be reduced with gas A stable foam cement will have discrete air bubbles that lower the density of the slurry but do not dilute the strength as much as water Hollow ceramic spheres can be used for the same purpose The spheres will be crushed, however, if the hydrostatic pressure is too high
The last common extender is pozzolan (sometimes called poz) Fly ash is the most commonly used pozzolan Fly ash alone has a density slightly less than Portland cement, so it does not reduce slurry density very much However, because fly ash is cheaper than cement, it can reduce the cost of the composition if, for instance, the job is performed with half cement and half fly ash Normally, some bentonite is added to a cement/pozzolan blend, which makes it possible to add more water
Lost circulation additives – marco plugging materials
Lost-circulation additives are used to plug zones that have a tendency to draw in fluid because they are unconsolidated or weak Large particulates can be placed in the cement slurry to prevent fracturing or to bridge existing fractures These particles should have a broad particle size distribution, should not accelerate or retard excessively, should have sufficient strength to keep a fracture bridged, and should be inexpensive and non-toxic The most common materials are ground coal, ground Gilsonite, and ground walnut hull Fibrous and flake materials are also used as lost- circulation materials The fibrous materials are normally inert polymers such as nylon, and the flake materials are cellophane or similar materials
Expansion additives - solid state crystal growth
Expansion additives cause the exterior dimensions of set cement to grow slowly when the cement is in the presence of downhole fluids This minor growth of the exterior dimensions of the slurry causes the cement to bond better to pipe and formation The most common additives for this use are based on calcium sulfoaluminate and calcium oxide
Challenges and Solutions of Cementing HPHT wells
- The Effect of Wellbore Temperature: One of the most important factors controlling the chemical reaction and performance results of a cementing composition is the wellbore temperature In HPHT wells, the cement slurry becomes sensitive to high temperature so that the thickening time of the slurry is highly reduced, making the cement set faster than in average temperature wells Temperature also affects the rheological properties of the cement slurry Ravi and Sutton (1990) mentioned that the plastic viscosity (PV) and yield viscosity (YV) decrease with an increase in temperature
Therefore, the cement slurry is subjected to progressively increasing temperature from the time it is mixed on the surface and pumped into the well until the time the cement cures and the formation adjacent to the wellbore return to their ultimate static temperature Circulating temperature and static temperature both affect cement design Circulating temperature refers to the temperature the slurry encounters as it is being pumped into the wells Static temperature refers to the formation heat the wellbore fluids will be subjected to after circulation is stopped for a set period of time
Knowing the bottom hole static temperature (BHST) is important for design-ing and assessing long-term stability or rate of compressive strength development for a cement slurry Determining BHST is especially important in deep-well cementing— where the temperature differential between the top and bottom of the cement can be high For example, cement slurries that are designed for safe placement times may be overretarded at top-of-cement (TOC) temperatures, resulting in poor compressive strength development Generally, if the static temperature at the top of the cement column exceeds the BHCT, over retardation is not expected Precise temperature readings are essential for cementing purposes An error as small as 5° to 10°F can significantly affect results even though slurry materials are chosen to minimize the effect of slurry sensitivity, however Properties of some cement systems, and the conditions in which they are applied, dictate the need for the designer to know wellbore temperature Generally, cement sensitivity increases as BHCT increases As a result, all laboratory tests performed to improve slurry properties should be run using samples of the same batch of cement, mixing water, and chemical cementing additives that will be used during the job Downhole conditions must be duplicated as closely as possible The best method of estimating bottom hole temperatures in horizontal or deviated wells is to simulate temperatures with the Enertech temperature simulator
Although (BHST) affect the curing properties of the cement, Bottom hole circulating Temperature (BHCT) has an even greater influence
BHCT is the temperature that influences the thickening time or pumpability of the cement slurry The BHCT is normally calculated from a set of temperature schedules published in API specification 10 Recently, several different temperature subs have been used in many wells in the United States These wells have provided detailed information that was not available when the first circulating temperature relationship was developed As a result, API has used this new set of data to develop a better overall correlation for calculating BHCT
Since accurately estimating BHCT is essential, designers should not rely on the API schedules alone when cementing deep wells Temperatures should be verified by some form of actual downhole measurement, preferably during the circulation phase
Halliburton has developed the BHCT II recorder, a temperature gauge that can reliably measure and record BHCT
- Effect of Pressure: Pressure has effects on both the well and the drilling fluid and cement slurry In cases where the pressure had not been properly estimated, the selected casing will not be able to withstand the pressure from the formation which will invariably lead to a collapse of the casing in the well and therefore a kick is encountered Weighting agents are used to create minimum over balance and they reduce the pump ability of the cement thereby accelerating the development of premature compressive strength
- Small Equivalent Circulating Density Window: As the depth of well increases, the increased hydrostatic head causes an increase in ECD due to compression and increase in temperature causes a decrease in ECD due to thermal expansion
- The Degradation of Post-Set Cement Due to High Temperature: In HPHT formations, the wells are subjected to high temperature variations and these changes affect both the formation and the casings, causing expansion and contraction This expansion and contracting of casing and plastic formation like salt causes cracks in the already set cement (Elxeghaty et al, 2007)
- Large Stresses on Post-Set cement for Life of well: The setting of cement is by the reaction between water and cement This process is called hydration and if it continuous, the pore pressure in the setting cement reduces with its pore spaces The post-set cement consisting of minimal number of pore spaces when subjected to high loads in deep wells compression sets in and destroys the cement sheath by compaction of matrix porosity (Elzeghaty at al, 2007) This destruction of cement matrix can be said to be caused by mechanical failure or damage and they create cracks in the cement matrix These cracks are pathway for the migration of gas from the formation to the surface, thereby shortening the life of the well because the integrity of the cement has been compromised
- Gas Migration through Cement: Migration of gas through the cement has been an industry problem for many years Al-Yami et al (2009) pointed out that approximately 80% of wells in Gulf of Mexico have gas transmitted to surface through cemented casing Gas migration causes cement to either keep gas confined to its necessary production pathway or to remain within its zone Two primary types of gas migration have been identified: short-term and long-term gas migration Short- term migration occurs before the cement sets, and long-term migration develops after the cement has set
Short term Gas Migration: The most widely accepted cause for gas migration through unset cement is that the cement is incapable of maintaining overbalance pressure (Figure 3.1) After the cement slurry is placed downhole, it initially behaves as a fluid and fully transmits hydrostatic pressure to the gas-bearing formation This overbalance pressure prevents gas from percolating through the cement slurry (Figure 3.2-A) Sometime after the slurry is placed in the annulus, it will develop gel strength (Figure 3.2-B) Gelation allows the cement to support its own weight, reducing the capability of the column to transmit hydrostatic pressure to the gas zone As gelation occurs, the cement loses filtrate to permeable formations, causing a loss of overbalance pressure, which then allows gas to enter the annulus and percolate through the gelled cement (Figure 3.2-C) If gas begins to migrate, it will continue to percolate at a rate proportional to the volume reductions occurring in the slurry until the cement has developed enough gel strength to prevent further percolation (Figure 3.2-D)
Figure 3.2 Gas channel forms under the following conditions
A Initially after cement placement, slurry behaves as a fluid and transmits full hydrostatic pressure
B Static gel strength development begins; meanwhile, fluid is lost from cement slurry to permeable formations, causing volume reductions
C Cement slurry static gel strength reduces transmission of hydrostatic pressure simultaneously as volume losses occur Together these factors cause loss of overbalance pressure, permitting gas to enter and percolate through the unset cement
D Gas percolation leads to the formation of discrete gas channels throughout the unset cement Gas may channel to a lower pressure zone or back to the surface Once formed, these channels will remain in the set cement
Long-Term Gas Migration: Long-term or “delayed-onset” gas leakage occurs sometime after the cement job was performed and considered successful As with short-term gas migration, the best method of eliminating long-term gas migration is squeeze cementing However, carefully designing the cement slurry, planning the job, and using specific cement additives—particularly expansion additives—can help prevent long-term gas migration Long-term gas migration is generally indicated by gas flow at the surface through the annulus, sometimes as early as a few weeks after the cement job is performed Flow volumes are slight-to-moderate and become more severe intime A noise log is probably the most reliable method of locating the source of the problem Cement bond logs (CBL) may not be sensitive enough to detect a discontinuity in the cement sheath, and pulse echo technology (PET) only evaluates the cement/pipe interface
Figure 3.3 Example of long-term gas migration problems
There are two suspected causes of long-term gas migration: inadequate drilling fluid displacement and the cement debonding from the casing after setting Inadequately displacing the drilling fluid during cementing prevents a good bond from forming between the pipe and the cement and/or the cement and the formation Incomplete displacement or excessive filter cake buildup also can create drilling fluid channels in the cement As time passes, the drilling fluid and cake dehydrate and shrink due to gas flow, resulting in a highly permeable pathway for gas migration The second suspected cause is the cement separating from the casing after it has set One reason for this debonding is that the casing diameter changes after the cement has set because of pressure or temperature changes during workovers or stimulation treatments The resulting long-term gas migration occurs through a discontinuity in the cement sheath either through (1) micro-flow channels in the drilling fluid or (2) through micro annuli between the pipe and cement or be-tween the formation and cement
When gas is flowing through drilling fluid channels and filter cake, the flow volume can usually be expected to increase as the drilling fluid dehydrates and shrinks
Cements also naturally undergo a minor volume reduction during the setting process
HPHT WellLife Cement System Design Process
The WellLife concept is a synergistic approach to cementing a well based on the mechanical properties of the cement sheath and how the cement interacts with the surrounding environment The WellLife approach integrates a Finite Element Analysis model to determine if a cement with given mechanical properties will survive the stress and strain state associated with the operations of the well Using WellLife software system as an interface used to quantitatively evaluate the cement sheath integrity for a given location in a well when the anticipated operations are applied This includes operation such as drilling, pressure testing, completion, production, stimulation and abandonment This results in a time dependent analysis of whether cement sheath survives Parallel with WellLife software, iCem software will also be used to design the cement job using actual data
3.2.1 Data to collect to design cement for HPHT wells:
The essential data types below contribute to every cementing job design especially it’s unique to HPHT cementing conditions and pertain especially to any specific problem for HPHT wells
1 Offset data: Collect as much offset data as possible to refer whenever applicable when making recommendation
2 Particular and general goals for the cementing operation: A firm understanding of customer goals is required to consistently create the ideal solution
3 Wellbore schematic which include Hole/bit size; pipe size; Excess for lead and for tail; Casing points; Formation types
4 Fracture pressure profile and Pore Pressure profile: gradient vs depth
5 Directional profile: normally vertical for this portion of the well but if not, deviation will modify the centralizer recommendation
6 Mud weight vs depth: Specific to the interval to be cemented
7 Mud rheology: Specific to the interval to be cemented and for HPHT sections, to be conducted at the expected bottom hole temperatures
8 Mudline temperature, BHST and possibly BHCT 9 TOC: TOC can also be top of the lead cement when lead and tail are run 10 Tail cement length: At least 500ft of tail slurry, depending on buckling simulations
11 Shoe track length: At least 80ft (though 120ft is strongly recommended) for wells at depths >15,000ft
12 Depth of last casing: Depth at which the liner will be set
13 Rat-hole length: Try to minimize the rat-hole length since leaving open formations can lead to problems in further strings
14 Thickening time safety factor: Double the placement time to avoid overretaring and delaying the initial set of cement (include surface mixing time if slurry is to be batch mixed)
15 Slurry density: Dependent on fracture pressure, pore pressure and GFP
16 Geologic data: are estimated depths for potential and overpressure zones (according to geological prognosis available? Are formations unstable or have they historically shown consolidation problems?
17 Log data from offset wells: are open hole logs from offset wells available so that we can estimate rock properties and investigate potential problem zones?
18 Drilling reports: Have any lost circulation, weak, or overpressure zones been found?
19 Casing specifications: Which threads are required for the project – conventional or premium? What about special drifts?
3.2.2 WellLife/Elastic cement slurry design [17] [21]
This section examines the factors involved in designing a slurry for HPHT wells by covering the following topics:
Poisson’s ration and Young’s modulus modification
Gas Migration Theory and Control
- Poisson’s ration and Young’s modulus modification
What is Young’s Modulus and Poisson’s ratio and how to modify it?
Young’s modulus is also called modulus of elasticity or stiffness and is a measure of how much strain occurs due to a given stress Because strain is dimensionless Young’s modulus has the units of stress or pressure
Figure 3.3a: Horizontal stress level developed in block/mortar assemblies [21]
Young's modulus, Poisson's ratio, and bulk modulus of hardened cement under controlled different relative humidity were measured by ultrasonic method as well as direct tensile loading test It was experimentally confirmed that Young's modulus, Poisson's ratio, and bulk modulus of hardened cement paste decreased as decrease in equilibrium relative humidity especially in the range above 40%RH And in the range below 40%RH, experimental results of direct tensile loading test showed the decrease in Young's modulus and Poisson's ratio while the experimental results of ultrasonic test showed slight increase of Young's modulus and almost constant behavior of Poisson's ratio For the decrease of Young's modulus and Poisson's ratio can be explained by the reduction of load-bearing water in the hardened cement paste due to drying, and slight increase under 40%RH by ultrasonic test can be explained by the increase of Si-O network of C-S-H due to drying
WellLife additive is an elastomeric material designed to help improve the elasticity of the set cement sheath It modifies the mechanical properties of the set cement, primarily by lowering the Young’s modulus and raising the Poisson’s ratio
WellLife additives are generally used in conjunction with the WellLife® service
The WellLife service is a process for improving the safety and the economics of oil and gas wells by applying these technologies
The WellLife® model is the result of a joint collaboration between Halliburton, Shell, and TNO (Building and Construction Research, The Netherlands) The model has been validated through experimental studies and field tests The WellLife model is backed by development and testing of cement slurries to meet the properties required for long-term zonal isolation Testing of cement specimens in a tri-axial cell under confining pressure is a part of the WellLife service Material properties, such as Young's modulus, Poisson’s ratio, friction angle, and cohesion of the cement sheath, are obtained from this test Placement of the engineered cement slurry is designed using OptiCem™ and WellCat™ engineering software programs The material properties of different cement formulations are compiled in a database and are an integral part of the program
How WellLife slurries modify Young’s modulus and Poisson’s ratio?
Because many parameters affect the Young’s modulus and Poisson’s ration of cement samples, some of the parameters include water ratio, solid ratio, time of cure, temperature of cure, pressure, density, and modulus of other materials in the sample
A general trend is given in Figure 3.4a & 3.4b [6]
Figure 3.4a General trend for modification of Young’s modulus with elastomers
Figure 3.4b General trend for modification of Poisson’s ratio with elastomers
Figure 3.5a General trend for modification of Young’s modulus with elastomers
As you can see, the higher concentration of 987, the lower the YM Typical oilwell cements can have a Young’s modulus of 2,000,000 psi WellLife service slurries containing 16 to 24% elastomer bwoc can have a Young’s modulus close to 1,300,000 psi, and slurries containing 40% bwoc elastomers can have a Young’s modulus close to 600,000 psi
Table 3.1 Comparison of Compressive Strength, Young’s Modulus and Poisson’s Ratio between WellLife 665 Additive and FDP-987-10 Material
Figure 3.5b General trend for modification of Poisson’s ratio with elastomers
As with Young’s modulus, a direct correlation with respect to the amount of FDP- C987-10 material is difficult to establish Some of the parameters include water ratio, solid ratio, time of cure, temperature of cure, pressure, density, and modulus of other materials in the sample A general trend is given in Figure 3.7
Typical Young’s modulus values are between 0.8-1.8Mpsi for cements Values can be higher or lower than this, but most “standard” values fall within this region This value also tends to scale with density
Poisson’s ratio is set between 0-0.5 Typical oilwell cements can have a Poisson’s ratio of 0.1 Most HPHT cement have a value of around 0.18-0.22 WellLife service slurries containing 16 to 24% elastomer bwoc can have a Poisson’s ratio close to 0.14, and slurries containing 40% bwoc elastomers can have a Poisson’s ratio close to 0.20
The bottom line is we want the higher amount of WellLife 987 in our slurries because it offers better mechanical properties (YM, Poisson’s Ratio, etc.) However, it tends to be limited by the ability of being able to mix cement in the field and economics (how much the overall slurry costs) Therefore, the general rule of thumb is 30% bwoc In practice, we might aim for something in between, say 15% bwoc Test it and see how it mixes in the lab If the slurry is thin and easily mixable, we can go to 20% bwoc and repeat the process
Elastic mechanical properties of cement such as Poisson’s Ratio, Young’s Modulus, Bulk Modulus and compressive strength can be continuously measured by mechanical properties analyzer equipment of Chandler Engineering, Model 6265 (MPRO) under HPHT conditions This instrument measures the compressional and shear sound velocities through the cement sample and uses industry-accepted equations to determine the Poisson’s ratio and Young’s modulus
Figure 3.6: Model 6265 Mechanical Properties Analyzer
Measurements: Poisson’s Ratio, Young’s Modulus, Bulk Modulus, Compressive Strength
Operating Conditions: 50°F - 110°F / 10°C - 43°C – non-condensing Maximum Temperature: 400°F / 204°C
Figure 3.7: Report of 6265 Mechanical Properties Analyzer
- Wellbore Temperatures: One of the most important factors controlling the chemical reaction and performance results of a cementing composition is the wellbore temperature In oil well cementing, the cement slurry is subjected to progressively increasing temperatures from the time it is mixed on the surface and pumped into the well until the time the cement cures and the formations adjacent to the wellbore return to their ultimate static temperature Circulating and static temperature both affect cement design Circulating temperature refers to the temperature the slurry encounters as it is being pumped into the well Static temperature refers to the formation heat the wellbore fluids will be subjected to after circulation is stopped for a set period of time Although static temperatures affect the curing properties of the cement, circulation temperature has an even greater influence Bottom hole Circulating Temperature Bottom hole circulating temperature (BHCT) is the temperature that influences the thickening time or pumpability of the cement slurry
The BHCT is normally calculated from a set of temperature schedules published in
API Specification 10 Recently, several different temperature subs have been used in many wells in the United States These wells have provided detailed information that was not available when the first circulating temperature relationship was developed
Applying WellLife slurry for cementing HPHT wells at Y field
Drilling and cementing for wells in this Y field have always been very challenging because of deep and high temperature, high pressure offshore wells along with very tight window between pore pressure and fracture gradient window and multiple reservoirs target The wells average more than 4500m MD and 4000m TVD Figure
3.12 shows one actual well schematic contains 8 strings with 11 ắ” expandable liner contingency had been used in Y field The general well structure including 30” conductor casing, 22” surface casing, 18” intermediate liner, 16” contingency intermediate liner, 13 5/8” intermediate casing, 11 ắ” contingency expandable liner, 10” production liner, 10” x 10 ắ” production tieback, 7 5/8” contingency liner and 5 ẵ” production liner
Figure 3.12: Well schematic contains 8 strings to reach to multiple reservoirs
One of the main challenges leading to the requirement of multiple strings of casing, liner and tieback to reach to target reservoirs is very narrow operational Pore Pressure – Fracture Gradient window Figure 3.13 shows very narrow window PP-FG 0.8ppg for a well in Y field The operator had to apply Manage Pressure Drilling (MPD) to help maintain Constant Bottom Hole Pressure in order to drill a long open hole ~ 906 meters in the narrow window with minimum near-balanced static mud weight possible applying surface back pressure using MPD choke manifold and 3 rd assigned rig pump
Figure 3.13: Pore Pressure – Fracture Gradient contains very narrow window 0.8ppg
3.3.2 Solutions applied in cement design for 5-1/2 casing of well in Y field
The key element to design and execution of cementing the casing strings successfully in Y field, one of the most challenging HPHT environments in Nam Con Son Basin is special single blend for various HPHT elastic cement densities
One of the challenges was to design a single dry blend that could be done in onshore bulk plant which would be suitable for a 16.5ppg to 18.5ppg slurry Not only this would simplify operations, but it would also reduce the risk, the overall cost to the operator by eliminating the need for excess chemicals (backup) and boat trip to refill for next cement job
The design of complex slurries requires a careful combination of chosen additives that will positively interact with each other at the full temperature range the slurry is exposed to The slurry must be mixable at surface, while being stable downhole, having the correct properties while it is a liquid, and having the correct properties once it sets up hard
As more particles of different shapes and sizes are added to slurry this design becomes more difficult to manage Due to the need for long-term isolation, the cement matrix requires WellLife® additives to modify the set-cement sheath’s mechanical properties with the goal of making it less brittle, more resilient, and more elastic than conventional cement so it can withstand stresses created by well operational pressures and temperature differentials
The special WellLife® blend contains high concentration of particles approximately 15 times larger than that of cement to enhance flexibility, fiber 100 times longer than cement diameter to enhance tensile strength, silicate particles 10 times larger than cement to avoid strength retrogression at high temperature, and finally platelet or spherical particles to increase the density of the slurry This mixture of different particles shapes and sizes is what affects the slurry mixability at surface, rheology and Equivalent Circulating Density (ECD) downhole, and the amount of water needed to successfully hydrate the slurry downhole while maintaining surface mixability for a desired density
In the effort to create a single blend suitable for a 16.5ppg to 18.5ppg slurry the water ratio is the critical variable that is adjusted to maintain the density while hold the weighting agent, elasticity and tensile strength variables constant while being able to achieve mixability at surface which achieves requirements downhole
The special elastic blend including:
Silica flour: prevents strength retrogression at high temperature
Special weighting agents: helps increase slurry density, improve bulk transfer and be more stable downhole with lower ECDs
High temperature expansion additive: helps reduce the risk of micro-annulus
Heavyweight Elastomeric cement additive: helps increase cement sheath’s ability to resist cumulative stress and cyclic loading by lowering the Young’s modulus and raising Poisson’s ratio
Tensile strength enhancer: helps increase the tensile strength of the set cement without significantly decreasing the compressive strength
Figure 3.15 and 3.16 show the different between Conventional cement and WellLife cement
Figure 3.15 Conventional cement sheath with catastrophic failure
Figure 3.16 WellLife cement resiliently withstands load
WellLife® Stress Analysis: models the integrity of cement sheath and the risk of its failure as it is subjected to different well operations through life of the well This model helps determine if cement can withstand multiple stresses from pressure test, temperature cycling, fracturing, production and modes of cement failure: radial cracking, deformation or debonding through life of the well The results from WellLife® Stress Analysis help to tune the slurry design by lowering Young’s Modulus, increasing Tensile strength, Figure 3.17 shows the different cement bonded remaining capacity with actual operational load conditions: pressure test casing, temperature cycling and production in 15years for a HPHT well between conventional cement (average remaining capacity is ~35%) and advanced elastic cement (average remaining capacity is ~70%)
Figure 3.17 Remaining capacity between conventional and WellLife cement
To achieve above result, detail experiments are as follows:
Liner measured depth: 3,632m BHST temperature: 160°C True vertical depth: 3,604m BHCT temperature: 135°C Depth to top cement (DP in): 2,737m Drilling mud type: SBM Drilling mud density: 17.10ppg
0-559m 5 1/2in 21.9ppf VX54 Drill pipe (S135 VX54)
5 1/2in 51.42ppf HW Drill pipe 2,737-3,632m
0-2,837m 13 5/8in 88.2ppf casing (12.375in ID) 2,837-2,888m 14 1/2in 65ppf casing (13.642in ID) 2,888-
SPACERS Spacer - 160.0bbl Tuned Spacer III at 17.30ppg
Drill Water 26.19 gal/bbl (265m OH annular fill / 27min contact time)
Tuned Spacer III 18.00 lb/bbl
Dual Spacer Surfactant B 0.70 gal/bbl Sem-8 0.70 gal/bbl
Contact times are based on the displacement rate
Halad-413L 0.40 gal/sk Surface yield: 2.069 ft³/sk
SCR-742L 0.36 gal/sk Total mixing fluid: 8.34 gal/sk
Note that %BWOC are based on a 94 lb sack, since of the 198.34 lb sack of blend only 94 lb is cement
Figure 3.18.UCA chart at BHST 160Deg C
Figure 3.19 TT chart at Baseline 135Deg C – cement sample from Silo3
Figure 3.20 SGS chart at BHST 160Deg C
Figure 3.21 UCA chart at BHST 160Deg C
Liner measured depth: 4,643m BHST temperature: 185°C True vertical depth: 4,598m BHCT temperature: 160°C Depth to top cement (DP in): 3,435m Drilling mud type: SBM
CMT on top of liner (DP in): 50m Drilling mud density: 17.10ppg CMT on top of liner (DP out): 30m
0-1,308m 5 ẵ in 21.9ppf Drill pipe (S135 VAM Express VX 54) 1,308-2,950m 5 ẵ in 35.88ppf FH Drill pipe (S135 FH VAM EIS) 2,950-3,485m 5 ẵ in 51.42ppf HWDP Drill pipe (VAM Express VX54) 3,485-4,643m 5 ẵ in 29.7ppf Liner (SM13CRS-110 VAM-SLIJ-II)
0-775m 10 ắ in 73.2ppf casing (9.394in ID) 775-3,633m 10 in 68.7ppf casing (8.624in ID) 3,633-3,634m 12.25 in open hole (10% excess) 3,634-4,643m 8.5 in open hole (10% excess)
SPACERS Spacer - 150.0bbl Tuned Spacer III at 17.40ppg
Drill Water 25.74gal/bbl (357m OH annular fill / 30min contact time) Tuned Spacer III 18.00 lb/bbl
Dual Spacer Surfactant B 0.80 gal/bbl
Contact times are based on the displacement rate
BD SPECIAL BLEND Surface density: 17.50 ppg
Halad-413L 0.40 gal/sk Surface yield: 2.078ft³/sk
SCR-742L 0.38 gal/sk Total mixing fluid: 8.41gal/sk
Note that %BWOC are based on a 94 lb sack, since of the 198.34 lb sack of blend only 94 lb is cement
Casing/Liner Size 5.5 in / 139.7 mm Depth MD 4644 m / 15236 ft BHST 185°C / 365°F
Hole Size 8.5 in / 215.9 mm Depth TVD 4598 m / 15087 ft BHCT 160°C / 320°F
Mud Supplier Name MI Swaco Mud Trade Name Density 17.1 lbm/gal
Conc UOM Cement/Additive Sample Type Sample Date Lot No
100 % BWOC Holcim Class G Rig 06.11.15 CL-0515-CM-
35 % BWOC SSA-1 (Silica Flour) - PB Rig 06.11.15
40 % BWOC HI-DENSE No.4 (PB) Rig 06.11.15
0.6 % BWOC GasStop HT (PB) Rig 24.01.16 366A0
Slurry Density 17.5 lbm/gal Slurry Yield 2.078 ft3/sack
5.95 Gps Total Mix Fluid 8.41 Gps
Water Source Drill water Water Chloride 450 ppm
Verification Test Results Request ID 2301825/8 Mixability (0 - 5) - 0 is not mixable
Mixability rating (0 - 5) Avg rpm mixing under load (~12,000)
FYSA Viscosity Profile & Gel Strength
Thickening Time, Baseline 160Deg C – Silo 1
Static Gel Strength (SGSA), BHST - Silo 1
Temp (°F) Pressure (psi) Time 100 lb/100ft2
CSGSP or 100-500 lb/100ft2 (hh:mm)
UCA Comp Strength, BHST - Silo 1
End Temp (ºF) Pressure (psi) 50 psi (hh:mm) 500 psi (hh:mm) 12 hr CS (psi)
UCA Comp Strength, TOL Silo 1
End Temp (ºF) Pressure (psi) 50 psi (hh:mm) 500 psi (hh:mm) 12 hr CS (psi)
Thickening Time, Baseline 160Deg C – Silo 3
UCA Comp Strength, BHST Silo 3
End Temp (ºF) Pressure (psi) 50 psi (hh:mm) 500 psi (hh:mm) 12 hr CS (psi)
Static Gel Strength (MACS II), BHST silo 3
Temp (°F) Pressure (psi) Time 100 lb/100ft2
Time 500 lb/100ft2 (hh:mm)
CSGSP or 100-500 lb/100ft2 (hh:mm)
API Sedimentation Test, BHST Silo 3
Temp (ºF) Result Type 1 2 3 4 5 AVG S.G St DEV
Figure 3.22 TT chart at Baseline 160Deg C-Silo1
Figure 3.24 UCA chart at BHST 185deg C-Silo1
CSGSP or 100-500 lb/100ft2 (hh:mm)
Figure 3.25 UCA chart at TOL 155deg C - Silo1
Figure 3.26 TT chart at Baseline 160deg C-Silo 3
Figure 3.27 UCA at BHST-Silo3
Time 100 lb/100ft2 (h:m) Time 500 lb/100ft2
CSGSP or 100-500 lb/100ft2 (hh:mm)
EVALUATE CEMENT QUALITY IN 5-1/2 CASING OF
Running and Interpreting Bond Logs with WellLife Cement
The primary functions of the cement sheath placed between the casing and the formation are to support the casing and to seal the annulus to the flow of fluid (liquid or gas) The objective of cement-sheath evaluation is to quantify the ability of the cement annulus to provide these functions Evaluating the hydraulic sealing function of the cement annulus is the most important and the most difficult part of cement evaluation In essence, this process involves detecting existing or potential fluid migration pathways that may exist between the casing and the formation shortly after the cement has been emplaced These pathways are formed by material that may be movable under differential pressures between formation intervals (Formation-Fluid Migration After Cementing) Specific examples are a cement sheath that is completely absent, channels in the cement running axially along the borehole, and gaps between the cement and the casing or formation Devoid of cement, these pathways are filled with water, gas, mud cake, drilling fluid gel, or formation material It is useful to know their size, vertical extent, circumferential location, and the material with which they are filled Ideally, it would be desirable to obtain a scan of the cement sheath analogous to the ultrasonic scans that are used to image the human body In summary, the cement evaluation is based on following factors:
Top of cement: to be evaluated from the top casing of the well to actual cement in annulus to measure the actual
Conventional Cement Bond Logs measure the received amplitude, and hence the attenuation rate, of a 20 kHz acoustic signal from a mono-pole source where the transmitter to receiver spacing is typically 3ft The received amplitude is a „radial average‟ from all around the pipe Assuming the cement sheath is greater than 0.75” thick, then:
The primary cement variable affecting attenuation is the shear modulus of the cement, or medium behind the pipe
The attenuation is proportional to the density of the cement
Shear coupling is required at the casing-cement interface to produce full attenuation
The attenuation is inversely proportional to the casing thickness
The received amplitude is dependent on the transmitted amplitude
The received amplitude is dependent on signal attenuation in the wellbore fluid WellLife is not considered to be a low density slurry as such, when compared to foamed cements for example, but it does have a very low shear modulus due to its elasticity This leads to a much lower attenuation rate than conventional class G slurries of similar density and leads to a pessimistic interpretation when conventional interpretation procedures are followed
The measurement principal of an acoustic Cement Bond Log can be likened to hitting a bell with a hammer With nothing behind the pipe it will ring, but with a solid behind the pipe, like cement, the ringing will be attenuated very quickly
The more „solid‟ the medium behind the pipe, i.e the higher the shear modulus, the higher the attenuation rate and the less it will ring, and conversely, the less
„solid‟ the medium the more it will ring Elastomeric cements, by design, have a low shear modulus, i.e they are less „solid‟, and so the pipe will ring significantly even when the pipe is well bonded, fully supported, and hydraulic isolation is provided by the cement sheath
Conventional acoustic Cement Bond Logs measure the received amplitude which is dependent on the transmitted signal amplitude as well as the attenuation rate, and hence the log must be calibrated accordingly There is an industry standard, although arbitrary, relationship between casing size and received amplitude as shown in Figure 4.1, which is chart CBL-3 from the Halliburton Chart Book
EL1001 For any Cement Bond Log to be valid it must be calibrated to read the corresponding amplitude, or attenuation rate, when in free pipe of the given casing size
Figure 4.1 Relationship between Received Amplitude (E1) and Casing Size
The relationship shown in Figure 4.1 is based on a wellbore fluid of fresh water and as different wellbore fluids will attenuate the signal at a different rate then this must also be accounted for before attempting to interpret the cement bond Figure
4 2 shows chart CBL-4 from the Halliburton Chart Book EL1001, which is a typical chart for this correction
Figure 4.2 Correction Factor (Amplitude Ratio) for different wellbore fluids
Once a correctly calibrated log has been corrected for fluid effects, the standard interpretation method is based on charts derived from empirical measurements, such as that shown in Figure 4.3 which is chart CBL-1 from the Halliburton Chart
It should be noted that this chart makes no mention of cement type or density, it is a purely generic chart Whilst specific charts could be derived for elastomeric cements they have not been for several reasons:
Elastomeric cements are highly variable in nature and slight design changes from a specific design used to derive a chart might yield a significantly different response
It would be impractical to derive a chart for multiple designs of elastomeric cement
The exact response of an elastomeric cement will also be a function of the load on the cement which in turn will be a function of temperature and pressure in the casing
Figure 4.3 Cement Bond Log Interpretation Chart
Cement with a low shear modulus will also produce a lower dynamic range between free and fully bonded pipe, further increasing the uncertainty in the interpreted result.
Conventional Cement Bond Log tools typically consist of two receivers, one at 3ft which provides the amplitude measurement, and another at 5ft used to record a full waveform display, typically referred to as the VDL The VDL provides a qualitative indication of the cement to formation bond where the amplitude provides a quantitative indication of the cement to pipe bond
With elastomeric cements the VDL will have stronger casing arrivals present and formation arrivals may be less clear because of the strong casing signals This is not always the case though as the magnitude and timing of the formation arrivals depends on the velocity and impedance of the formation itself as well as the cement
Tools such as Halliburton’s CAST-V and Schlumberger’s USIT use a scanning head firing an ultra-sonic pulse, with a typical frequency of between 250 kHz and 350 kHz, to measure the acoustic impedance of the material behind the pipe The acoustic impedance is measured at anything from 36 to 100 discrete points around the pipe at every depth sample Along with an accelerometer measurement this allows a „cement map‟ to be produced which is orientated to the low side, which, due to the much higher resolution of this measurement, allows the radial placement of cement to be investigated and the identification of channels etc
These tools do not require any calibration as the current field processing algorithms utilize the amplitude of the first reflection to effectively „self-calibrate‟
Acoustic impedance is defined as the product of density and velocity and hence the acoustic impedance of cement is proportional to the density Lightweight cements, and especially foamed cements, can have acoustic impedances comparable to, or even less than water Figure 4.4 shows the range of acoustic impedances for the typical materials encountered
Figure 4.4: Acoustic Impedance of typical materials present behind pipe
Evaluation result of WellLife cement quality for HPHT of well in Y
Cement quality includes different factors in which cement slurry play the most important role to provide mechanical support for the casing and an isolation seal between the casing and the formation and stable for the production time without leaking After finishing cementing the casing, cement bond evaluation accurately evaluates the integrity of the cement sheath surrounding the casing to determine the quality of hydraulic zone isolation and can be deployed in both memory and conventional acquisition modes to provide reliable bond logs in a variety of casing sizes which shows:
Displacement quality to show filled-up level of cement slurry in the annulus
Connection of cement slurry and casing and wellbore
We mainly evaluate the cementing quality of production casing and the casing at high temperature high pressure section of a well and we normally run Cement Bond Log (CBL) and Variable Density Log (VDL) The CBL and VDL result clearly show in each 100m of the well along vertical depth cement quality and connection with the casing how many meters has good cement, how many meter only has partial cement and how many meter without cement The quality can be calculated as percentage
Figure 4.7 Examples of TT and Amplitude data
The amplitude should be checked for consistency against the reference amplitude for the pipe size, and against the VDL and Ultra-Sonic log responses if available
The amplitude example shown on the right in Figure 4.7 reads just over 50mV at the top and might be interpreted as free pipe, and calibrated accordingly, as this is 7” liner with free pipe amplitude of 62mV However, in this case that would be wrong as this is not free pipe There was a tail of 15ppg and lead of 8.5ppg, with the transition apparent in the amplitude about 1200 In the 8.5ppg lead the amplitude of 30-40mV is well bonded Above 400 there is 9-5/8” casing behind the liner giving lower amplitude still
If the amplitude was truly reading free pipe then the VDL would show strong casing arrivals, “tram lines”, with no formation arrivals If formation arrivals are obvious and the amplitude reads free pipe then the tool has been „over- calibrated‟ and is pessimistic, i.e it has been calibrated to read free pipe in pipe that is not free
The maximum amplitude should also be checked throughout the entire log as it should never read greater than free pipe If the amplitude reads greater than free pipe the tool has been over-calibrated
Where the amplitude is low the casing arrivals show be very weak or absent and formation arrivals should be much stronger However, depending on the rock the formation arrivals may be very weak or absent as well as this depends on the acoustic properties of the formation Comparison with an open hole full waveform sonic log can identify which zones have weak formation arrivals due to the rock properties so that this is not misinterpreted as poor cement bond
Figure 4.8 Casing Collar Locator Radial CBL of 5-1/2 tubing of well Y after cementing with WellLife Slurry
The thesis presents an overview of cementing in high pressure high temperature well in Y field Nam Con Son basin From the acknowledge challenges of cementing HPHT wells, research the components of WellLife cement from that proposing of applying WellLife slurry to the HPHT well at Y field and follow up with evaluation by cementing bond log
In the Y field heavyweight WellLife cement designs are common for all primary cementing jobs throughout the production casing, liner (special blend with fixed % of each component bwoc) The designs are adjusted by only a few liquid chemicals and water to fit to a specific wellbore condition This experimental work highlights the use of an advanced single WellLife cement blend that can be tuned specifically from 16.5ppg to 18.5ppg in HPHT slurry for both casing sizes and engineered development solutions for long-term zonal isolation which have proven over the past 8 years
The single appropriate WellLife cement blend not only simplifies operations and logistics, but it also reduces the risk, the overall cost to the operator by eliminating the need for excess chemicals (backup) and boat trip to refill for next cement job
The above Figure 4.7 shows CBL & VDL of 5-1/2 section of one of the well in Y field after cemented with WellLife Slurry Some area without cement can be visual catch from the log
In the good bond area, the amplitude line is low from VDL line shown that cement filled in the annulus has hardened The result from this log’s show that the quality of cement connection in production liner section is fairly good (90-100%) However, to evaluate cement of production liner in long production period including evaluation of mechanical connection of cement in long time, we have to redo the CBL and VDL in order to have solution in case finding of any problem
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Name: Luong Thi Hong Son (Sharon Son)
Date of birth: December 24, 1978 Residence: Ho Chi Minh City, Vietnam Nationality: Vietnamese
Languages: Vietnamese, English, Chinese Marital status: Married
Commenced: Mar, 2000 – now Company: Halliburton International Inc (17 years) Company: Chevron Vietnam (1.5 years)
Job title From year to year
Vietnam Business Development Manager Jan13 – Mar18
Account Manager – Business Development Apr12 – Jan13
Contracts Administrator/Chevron VN Jan11 to Apr12
Account Manager-Landmark Jan09 - Dec10
Customer Operation Specialist, Sr Jul06 – Dec08