IADC/SPE 135183 Drilling Expert System for the Optimal Design and Execution of Successful Cementing Practices A.S. Al-Yami, Jerome Schubert, SPE, Zenon Medina-Cetina, Texas A&M University; Ok-Youn Yu, Appalachian State University; all SPE Members Copyright 2010, IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition This paper was prepared for presentation at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition held in Ho Chi Minh City, Vietnam, 13 November 2010. This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright.

Abstract Cementing is an important factor in drilling and completion operations. Good cementing practices are required for a proper advancing in drilling and production operations. Successful cementing practices start with the design of effective cement slurries. However, to the best of the authors knowledge, there are no standard guidelines to help drilling engineers and scientists in the effective design of optimal cement slurries to be used in different well sections. The objective of this paper is to propose a set of guidelines for the optimal design of cement slurries, by integrating current best practices through a decision-making system based on Artificial Bayesian Intelligence. Best cementing practices collected from data, models, and experts opinions, are integrated into a Bayesian Network BN to simulate likely scenarios of its use, that will honor efficient designs when dictated by varying well objectives, well types, temperatures, pressures, and , drilling fluids. The proposed decision-making model follows a causal and an uncertainty-based approach capable of simulating realistic conditions on the use of cement slurries during drilling and completion operations. For instance, well sections and drilling operations dictate the use of the proper cement design which may include the use of specific additives according to the particular modeling scenarios. These include operations on surface casing, top jobs, intermediate casings, cementing in weak formations, squeeze treatment, kickoff and isolation plugs, horizontal, and vertical completions, among others. Potential operational problems that can lead to cementing failures are also discussed. Different methods of investigation and recommendations are presented in detail.

Introduction Different types of cements are used in drilling and completion operations to:

Isolate zones by preventing fluid migration between formations Support and bond casings Protect casing from corrosive environments Seal and hold back formation pressures Protect casing from drilling operations such as shock loads Seal loss circulation zones Cement costs can be minimized by eliminating expensive and unnecessary additives required in certain operations but not

in others. From common practice it is known that cementing slurries should be tested in advance, since each particular well has distinctive characteristics. Therefore, it is not possible to define a general guideline for all situations for the concentration of additives required for the cementing job (Sauer and Landrun, 1985). Effective communication is also an important factor for successful cementing jobs. Good coordination is required between the drilling engineer, the service company and the rig foreman. Applying quality control is critical for avoiding cement-related failures in the field. Knowledge transfer in cementing operations is therefore fundamental for the optimal design of the cementing job (Smith,1984). Field and lab experience are required for cementing specialists to help drilling engineers when designing cement slurries. In some occasions, cement failures can occur because of the lack of knowledge or lack of knowledge transfer.

Based on the facts discussed above, two objectives are proposed for improving the current cementing practices: To develop a cementing expert system capable of addressing a wide range of likely operations ranging from primary

cementing to remedial operations, by the use of a decision-making system based on Bayesian Networks, and

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To illustrate some of the best cementing practices in specific cases. Bayesian Methods The Bayesian paradigm can be defined as:

=

)()()(

)(evidencep

hypothesisphypothesisevidencepevidencehypothesisp

Representing the probability of a hypothesis conditioned upon the availability of evidence to confirm it. This means that it is required to combine the degree to plausibility of the evidence given the hypothesis or likelihood p(evidence|hypothesis), and the degree of certainty on the hypothesis or p (hypothesis) called prior. The intersection between these two probabilities is then normalized by p(evidence) so the conditional probabilities of all hypothesis can sum up to 1. This work introduces the use of Bayesian networks as a way to provide reasoning under uncertainty, using nodes representing variables either discrete or continuous. Arcs are used to show the influences among the variables (nodes). Thus, Bayesian networks can be used to predict the effect of interventions, immediate changes, and to update inferences according to new evidences. Bayesian networks are known as directed acyclic graphs because generating cycles are not allowed. The terminology for describing a Bayesian Network follows a hierarchical parenting scheme. A node is named a parent of another node named child if we have an arc from the former to the later. The arcs will represent direct dependencies. Evidence can be introduced to the Bayesian network at any node, which is also known as probability propagation or belief updating. It is important to define the conditional probability distributions to each node (Korb and Nicholson, 2004). In order to prove the concept and the benefits of using this approach, one simple model simulating the decision-making process of the selection of cementing formulations is introduced below. For this study, GeNIe (Graphical Network Interface) was used for calculations of the uncertainty propagation to build up the cementing expert system (Medina-Cetina and Nadim, 2008). Proof of Concept of the Proposed Decision-Making Model In order to prove the concept and the benefits of using this approach, one simple BDN model simulating the decision-making process of the selection of cementing formulations is introduced in Fig.1. This model contains one decision node (cementing type), four uncertainty nodes (Cementing Operations, Total Cost, Wellbore Isolation, and Consequences), and one value node (Cementing Expert System). In this Figure the cementing type (T) affects the cementing operations (O), the total cost (DC), and the Wellbore Isolation (Dw) nodes. Cementing type also affect Total Cost and Wellbore Isolation. Consequently, the probability of consequences (C) for each system is conditioned on Total Cost and Wellbore Isolation, which are the decision evaluation criteria for this model. Therefore, the propagation of information from cementing type ends in the Cementing Expert System (CES) variable representing the state of the utility for each possible system.

Fig.1: BDN model for the proof of the concept. Once the structure of the BDN is defined, it is required to define the conditional probability distribution associated with each node. The input data is provided in the form of Conditional Probability Tables (CPT) assigned to each node. These are

IADC/SPE 135183 3

given in Table 1 through Table 6. For the cementing type node, two different types are considered: low density cements (LC) and conventional cement (CS) (Table 1). The O node defines the probability states of cementing operations as multistage cementing and single stage cementing (Table 2). The Dw and Dc nodes define the probability states of Wellbore Isolation (Table 3) and Total Cost (Table 4) for each drilling system as high, moderate, and low (ordered values). In addition, the C node defines the extent of the probability states of the Consequences (Table 5), which are defined as best, intermediate, and worst. The input utility value associated with the Consequences is given in Table 6. The expected utility outcomes considering all possible cases of evidence set a minimum value of zero, which is the worse case, and a maximum value of one, which assumed to be the best case. The main goal after the required inputs are entered into the model is to simulate the uncertainty propagation from the existing sources of evidence, which means moving forward the information starting from the cementing operations node in this case (i.e. prognosis). The probability model needed for assessing each of the belief nodes is presented below. The evidence instantiation at Cementing Operations defines the probability of having different states of evidence as the belief of O:

(1)

Similarly for other nodes using the principle of total probability:

(2)

)()( OBelTOP =

=i

www DPDBelODP ()()( ii OxBelO ),()

(3) =i

ccc ODPDBelODP ()()( ii OxBel ),()

)()(),()(),( cj

jwicjwi

iCw DxBelDxBelDDCPCBelDDCP =

(4)

Finally, the CES for each system is calculated as:

(5)

Where U (C ) is the input utility values. The Conditional M bility Distributions (CMPD) of Dw and Dc can be

(6)

The CMPD of C can be calculated by using the equation (4). In this calculation, it is required to take into account the

(7)

(8)

Where P(O) is the prior and P(Dw|O) is the likelihood. Once the updated belief for O is calculated with the evidence of Dw

(9)

)()( ii CxUCBelCES =i

arginal Probaicalculated by using the equations (2) and (3) respectively. The results are summarized in Table 7 and Table 8. The example calculation of Dw with high probability state in CS condition would be:

93.0)19.030.01.0()( )( =+=LDDP highw

probabilistic inference of O before calculating Bel(Dw) or Bel(Dc). The basic task for any probabilistic inference system is to compute the posterior probability distribution for a set of query nodes, given values for some evidence nodes. This task is called belief updating or probabilistic inference. Inference in BDNs is very flexible as evidence can be entered about any node while beliefs in any other nodes are updated (Korb and Nicholson, 2004). If there is evidence say about O = multistage cementing (parent node), then the posterior probability (or belief) for Dw, which here is denoted Bel(Dw), can be read straight from the value in conditional probability input table given in Table 3 as P(Dw|O =multistage cementing). If there is evidence say about Dw = high (child node), then the inference task of updating the belief for O in LD (Low Density Cement) condition is done using a simple application of Bayes Theorem. The calculation would be:

= high, then the task of updating the belief for Dc can be calculated using equation (3). Results for each condition are summarized in Table 9. For instance, calculation of the updated Dc with high probability state in LD condition would be:

)()()(

))(

)(

highw

CementingMultistagehighwCementingMultistagew DP

ODxPOPhighDcementingmultistageO ===

032.0930.0

==1.03.0

(P

968.0930.0

==9.01

)()()(

)()(

)(

highw

CementingeSinglestaghighwCementingeSinglestagw DP

ODxPOPhighDcementingstageSingleO ===P

=i

iicc OxBelODPLDDP ),()()( 077.0)05.0968.90.0032.0( = + =

4 IADC/SPE 135183

Where Bel(Oi) is the updated O calc D |O ) is the input value given in Table 4. The CMPD of C (Table 10) is c

Where P(C|Dw , DCj) is the input CPT given in Table 5 By using the equation (5) and the results presented in Table 10,

(11)

C ) is the input utility values given in Table 6. This means that under these conditions, our selection of LDC

Table 1: Available Cementing Types

ulated by the equation (7) and (8), and P( c ialculated by using the results presented in Table 7 and Table 9. The example calculation of C

with Best probability state in LD condition would be:

=i

ciwiiij

cwbest DxBelDxBelDcDwCPDDCP )()(),(),(

.0)050.0030.040.0()050.0930.01()873.0930.05.0(

(10) 453

ithe CES for two different cementing types are assessed as shown in Table 11. The CES is the final value for each cementing type and the LD is selected as an optimal cementing type in this example because it has a higher CES value than the CC, Table 11. The example calculation of the CES for the LD would be:

+=

=i

iiLD CxUDBel )()(

+ =

.

CES 679.0)0( =095.05.0452.01453.0 ++=

Where U( i(low density cement) is more preferred over conventional cement since it has a higher utility value.

Cementing Type 1.Low LD) Density Cement (2. Conventional Cement(CC)

Table 2: CPT for P(O|T) Cem T) enting Operations P(O|

Cementing Type LD CCMultistage Cementing 0.1 0.9

Cementing in one stage 0.90 0.1

Table 3: CPT r P(Dw|O, T) Wellbore Isolation (Dw) T)

foP(Dw|O,

Cementing Type LD CC Ce s Multistage Cementing menting in one stage Multistage Cementing menting in one stagementing Operation Ce Ce

High 0.30 1 0.30 0.05 M e oderat 0.30 0 0.30 0.05

Low 0.40 0 0.40 0.90

Table 4: CPT for P(Dc|O, T) Total Cost (Dc) )

P(Dc|O,TCementing Type LD CC

Ce s Multistage Cementing menting in one stage Multistage Cementing menting in one stagementing Operation Ce CeHigh 0.90 0.05 0.10 0.05

M e oderat 0.05 0.9 0.10 0.05 Low 0.05 0.05 0.80 0.90

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Table 5: CPT r P(C|Dw, Dc) Consequences (C) c)

foP(C|Dw, D

Wellbore isolation High Low Moderate Total Cost High M High Low High M Low oderate Low Moderate oderate

Best 0.00 0.5 1.00 0.00 0.00 0.40 0.00 0.00 0.00 Inte ate rmedi 0.50 0.5 0.00 0.20 1.00 0.60 0.00 0.20 1.00

Worse 0.50 0 0.00 0.80 0.00 0.00 1.00 0.80 0.00

Table 6: Utility value for C Cementing Ex pert System

Consequences B t Interm Wes ediate orseU ) tility value, U(C 1.0 0.5 0.0

Table 7: CMPD of Dw Wellbor W|T)

e Isolation (DW) P(DCementing Type L D CC

High 0 0.930 .275M e oderat 0.030 0.275

Low 0.040 0.450

Table 8: CMPD of Dc Tota )

l Cost (DC) P(Dc|TCementing Type L D CC

High 0 0.135 .095M e oderat 0.815 0.095

Low 0.050 0.810

Table 9: Belief updates for O and Dc with evidence E of Dw.

Cementing Type LD CC Cementing Operations d P(O|Dw,T)Update Multistage Cementing 0.032 1.00 982 0.800 0 1.000 0.982 0.single stage cementing 0.968 0.000 0.000 0.018 0.018 0.200

W ellbore Isolation (DC) High E E

M e oderat E E Low E E

Total C) Upd d P(D |T) Cost (D ate CHigh 0.077 0.900 .099 0.090 0.900 0.099 0

M e oderat 0.873 0.050 0.050 0.099 0.099 0.090 Low 0.050 0.050 0.050 0.802 0.802 0.820

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Table 10: CMPD of C Co nsequences P(C|T)

C L ementing Type D CCBest 0 0.453 .322

Inte ate rmedi 0.452 0.569Worse 0.095 0.108

Table 11: CES for the systems C

Cementing Type LD CCem em 0 0enting Expert Syst .679 .607

ementing Expert Model was performed for a small model with limited options. To develop a model that can be used to

the well type enables the drilling engineer to set his/her evidence (i.e to select his

bles the user to select the objective of the operation. Different options are made

the ffe

es node combines the four uncertainty nodes (well type, required pumping time, objective and drilling

The user

CThe calculation shown above assist in performing successful cementing operations, a more comprehensive model is needed, as the one presented in Fig.2. Cementing experts opinions were used as evidence to build a model using the proposed Bayesian Network . Variable nodes allow the user to input desired well conditions that allows for generating the corresponding best cementing practices. Six uncertainty nodes are defined for this model (well type, objectives, bottom hole static temperature, pumping time, drilling fluids, and consequences). This considers three decision criteria. The three decisions are a) recommended cementing formulations, b) recommended spacer formulations and c) recommended operational practices. For this study, GeNIe (Graphical Network Interface) was used for calculations of the uncertainty propagation to build up the cementing expert system (Medina-Cetina and Nadim, 2008). The uncertainty node corresponding towell type) as oil well, or gas well. The bottom hole static temperature uncertainty node enables the selection of the temperature range. Temperature ranges were selected for oil and gas wells up to 400 F. Bottom hole static temperature affects required pumping time. The user can either select a temperature or a suitable pumping time for the proposed well section. Pumping time ranges up to 8 hours in this model. The Objective uncertainty node enaavailable for the user. These include kickoff and isolation plugs, squeeze cementing, single stage cementing, conductor, surface, intermediate and production casings. In addition, the objective uncertainty node has cementing long liners, expandable casings, and cementing CO2 injection wells. The Drilling Fluid Type uncertainty node shows possible options such as water based, water based with high Cl- content, and oil based mud. The Drilling Fluid Type mainly affects the spacer selection. The recommended cement formulations decision node contains all possible cementing slurries that correspond todi rent well type, objective nodes and bottom hole temperature. The recommended spacer decision node shows all possible spacer formulations (water, water based fluid, special spacer fluid with mutual solvent and water wetting additives). The recommended operational practices decision node shows required actions for each casing type such as multistage operation, optimum pump rate, surface shallow leaks and other best practices related to cementing such as top jobs and cementing plugs recommendations. The consequencfluid) and the three decision nodes (recommended cement formulations, recommended spacers and recommended operational practices). Cementing experts opinions were used to assign and define the node conditional probability distribution. The model is designed in a way to give the user options to design well cementing and best practices effectively. will select options that match his application from well type, bottom hole temperature or required pumping time, objective and drilling fluid. Then the model (cementing expert utility) will suggest optimum cement formulations, spacer formulations and operational practices that fit the given well conditions. Below are some best cementing practices decisions that were used in the drilling expert system. The uncertainty nodes (well type, required pumping time, objective and drilling fluid) effects on these decisions are also discussed.

IADC/SPE 135183 7

Fig.2: Cementing Expert Model Based on Bayesian network

rilling Expert System for the Optimal Design and Execution of Successful Cementing Practices

rio where the user select his conditions, Figs.3-6. The conditions are:

emperature: 300-400F

sed mud

DExample 1: Cementing Oil Production Liner This section shows the use of this model in one scena

Well Type: Oil well Bottom Hole Static T Objective: Production Liner Drilling Fluid Type: Water ba

8 IADC/SPE 135183

Fig.3: Selection of well type

Fig.4: Selection of Bottom hole static temperature

IADC/SPE 135183 9

Fig.5: Selection of well objective

Fig.6: Selection of drilling fluid

10 IADC/SPE 135183

The consequences node combines the four uncertainty nodes (well type, required pumping time, objective and drilling fluid) and the three decision nodes (recommended cement formulations, recommended spacers and recommended operational practices). Cementing expert opinion was used to assign and define the node conditional probability distribution. The model then calculates, based on the above conditions, the optimum practice to cement the liner, Figs.7-8.

Fig.7: The cementing expert system recommends formulation 13, operational note 5 and spacer 2 to be used in

this application

IADC/SPE 135183 11

Fig.8: The model showing more details for this application (Example 1)

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Example 2: Cementing Gas Long Production Liner The conditions are:

Well Type: Gas well Bottom Hole Static Temperature: 300-400F Objective: Long Liner Drilling Fluid Type: Oil based mud

The model then calculates and shows in Fig.9 the optimum practice to cement the long liner.

Fig.9: The model showing more details for this application (Example 2)

IADC/SPE 135183 13

Discussion of Results The drilling expert system for cement was based on field and lab experience which is not possible to mention in details in this paper. However, an Appendix A shows criteria outlining basic practices in cementing. Using this drilling expert system saves time by providing cementing practices to engineers and scientists. For the first example, selection of the following cement slurry design: Cement +35%BWOC silica flour+Expansion additive+Dispersant+ Fluid loss additive+ Retarder+ 0.01 gps Antifoaming agent is suitable. The temperature is high (300-400 F) which requires the use of retarder to delay setting of cement. Lignosulfonate and some carbohydrate derivatives such as xanthan gum, cellulose and polyanionic cellulose are common retarders. Viscosity of cement slurry also affect pumping properties, at high temperature the viscosity will be reduced which might lead to solids settling. To solve this problem, additives for viscosity control are used. Dispersants are used with cement slurry to improve the rheological performance especially at higher densities without the use of additional water. Expansion additives (for example CaO or MgO) are used to minimize shrinkage during cement slurry setting. The expansion additives are effective when bottom hole temperature is greater than approximately 300 F. Fluid loss additives are used to minimize hydration of water sensitive shale, to maintain the cement slurry water for the hydration process, and to minimize bridging in wellbore Also the use of silica source is required to prevent strength regression. Water based spacer can be used since we are using water based drilling fluid. The operational note indicate best field cementing practice for this case as the following: 1. Liner hanger representative should be on the rig floor at all times while the liner is being RIH especially when being rotated (via rotatry table with DP in the slips), and should ensure that the rotation torque at 15 RPM or lower does not exceed the maximum allowed rotating torque. 2. Pump enough spacer and cement 3. Pay attention to difference in temperature in case of long liners. Compressive strength of 500 psi is required at the top of the liner 4. After starting to pump cement downhole, begin to rotate the liner at 3 to 7 RPM. If observed surface torque is below maximum allowed surface torque, increase RPM to 15, otherwise attempt to rotate at any lower RPM if the observed surface torque is less than maximum allowable surface torque, up until plug bumps. 5. Actual volumes will be based on openhole caliper log. 6. Cement additives maybe revised after final confirmation testing 7. Cement will be batch mixed 8. Pump fresh water behind wiper plug and cement in lines ahead of water (1-2 bbl). 9. Slow displacement to 2-3 bpm before sharing the liner wiper plug. Do not over displace. 10. Record the maximum surface rotating torque observed during the cement job on the drilling report. 11. Pull four stands above the liner top and reverse circulation 1.5 DP volumes. Pull additional 5 stands and reverse out 1.5 DP volumes. Shut in well and apply 300-400 psi. WOC for 7 hours. Flow check then POH laying-down excess DP and liner setting tool. 12. When RIH with bit to drill top of liner cement, if no solid cement can be observed within 15-20 feet on TOL then wait additional time for cement to develop the required compressive strength. It should be noted that having soft cement at the top of the liner can be due to contaminants which may not indicate cement failure. For the second example (cementing Gas Long Production Liner), the same operational field note above can be applied. The spacer will be a water based spacer that has mutual solvent to water wet the formation for improved formation cement bonding, Since we have a long gas production liner the cement slurries should meet the following requirements, Al-Yami et al. (2007):

1- The thickening time must be sufficient to allow proper slurry placement. 2- Rapid compressive strength development at the top of the liner and the bottom. 3- The slurry must be easily mixable and must not exhibit free water or settling tendencies. 4- A fluid-loss of 100 ml/30 min.

In addition to conventional additives such as fluid loss, dispersants, silica source latex must be used.: For wells that show high gas migration potential we can use latex additive. Latex is a copolymer of AMPS, N-Vinylacylamide and acrylamide, Fink (2003). The following retarders combination are recommended Al-Yami et al. (2007):

Blend of salt and organic acid. Aromatic polymer derivative and blend of salt and organic acid. Sodium salt of alicyclic acid and aminated aromatic polymer.

Conclusions The Bayesian approach was found suitable for designing the cement expert system based on the factors mentioned above. The model can work as a guide to aid drilling engineers and scientists to formulate effective cement slurries for the entire well sections. Examples of best cementing practices, cement and spacer formulations were explained in this paper. Potential problems in cementing were outlined and discussed. The model has significant details that should help in providing effective cementing applications in oil and gas fields.

14 IADC/SPE 135183

References Al-Yami, A.S., Al-Arfaj, M.K., Nasr-El-Din, H.A., Jennings, S., Khafaji, A., Al-Ariani, M. and Al-Humaidi, A.:

Development of New Retarder Systems To Mitigate Differential Cement Setting in Long Deep Liners, paper SPE/IADC 107538 presented at the 2007 Middle East Drilling Technology Conference & Exhibition held in Cairo, Egypt, October 22-24.

Al-Yami, A.S., Nasr-El-Din, H.A., Jennings, S., Khafaji, A. and Al-Humaidi, A.: New Cement Systems Developed for

Sidetrack Drilling, paper SPE 113092 presented at the 2008 Indian Oil and Gas Technical Conference and Exhibition held in Mumbai, India, March 4-6.

Al-Yami, A.S., Nasr-El-Din, H.A. and Al-Humaidi, A.: An Innovative Cement Formula to Prevent Gas Migration Problems

in HT/HP Wells, paper SPE 120885 presented at the 2009 International Symposium on Oilfield Chemistry held in Woodlands, Texas, USA, April 20-22.

Al-Yami, A.S., Jennings, S., Al-Khafaji, A. and Al-Humaidi, A.S.: Well Cement Formulations for Increased Drilling

Hardness, US patent application 20090260545, October 2009. Al-Yami, A.S., Nasr-El-Din, H.A., Al-Humaidi, A.S., Al-Saleh, S.H. and Al-Arfaj, M.K.: Evaluation and Optimization of

Low-Density Cement: Laboratory Studies and Field Application, SPE Drilling & Completion Journal, 25 (1) 70-89, March 2010.

Benge, G.: Cement Designs for High-Rate Acid Gas Injection Wells, paper IPTC 10608 presented at the 2005 International

Petroleum Technology Confrence held in Doha, Qatar, November 21-23. Bensted, J.: Retardation of Cement Slurries to 250F, paper SPE 23073 presented at the 1991 SPE Offshore Europe held in

Aberdeen, UK, 3-6 September. Brothers, E., Chatterji, J., Childs, J.D., and Vinson, E.F.: Synthetic Retarder for High-Strength Cements, paper SPE 21976

presented at the 1991 SPE/IADC Drilling Conference held in Amesterdam,The Netherlands, 11-14 March. El-Hassan, H., Sultan, M., Johnson, C., Belmahi, A., Rishmani, L.: Using a Flexible, Expandable Sealant System to Prevent

Microannulus Formation in a Gas Well: A Case History, paper SPE 92361 presented at the 2005 MOES, Bahrain, 12-15 March.

El-Marsafawi, Y., Al-Yami, A.S., Nasr-El-Din, H.A., Al-Jeffri, A., Misran, M., Hasan, A. and Jain, B.: A New Cementing

Approach to Improve and Provide Long-Term Zonal Isolation, paper SPE 100558 presented at the 2006 Asia Pacific Oil & Gas Conference and Exhibition held in Adelaide, Australia, September 1113.

Eoff, L.S., Buster, D.: High Temeprature Sunthetic Retarder, paper SPE 28957 presented at the 1995 SPE International

Symposiuim on Oilfield Chemistry held in San Antonio, TX, 14-17 February. Fink, J.K.: Oil Field Chemicals, Gulf Professional Publishing 2002 Garvin, T.R. and Robert, M.J.: Cementing Practices-1972, paper 3809 presented at the 1972 Joint Meeting MMIJ-AIME,

Tokyo, May 24-27. Harms, W.M. and Febus, J.S.: Cementing of Fragile-Formation Wells with Foamed Cement Slurries, JPT (June 1985) 1049-

1057. Jennings, S.S., Al-Ansari, A.A., Al-Yami, A.S.: Gas Migration After Cementing Greatly Reduced, paper SPE 81414

presented at the 2003 Middle East Oil Show & Conference held in Bahrain, April 5-8. Korb, K.B. and Nicholson, A.E.: Bayesian Artificial Intelligence,Boca Raton, FL:Chapman and Hall/CRC, 2004. Kulakofsky, D. and Vargo, R.: New Technology for the Delivery of Beaded Lightweight Cements, paper SPE 94541

presented at the 2005 SPE Annual Technical Conference and Exhibition in Dallas, TX, 9-12 October. McPherson, S.A.: Cementation of Horizontal Wellbores, paper SPE 62893 presented at the 2000 Annual Technical

Conference and Exhibition held in Dallas, Texas, October 1-4.

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Medina-Cetina, Z. and Nadim, F.: Stochastic Design of an Early Warning System, Georisk, 2 (4), 223-236, December 2008. Mukhalalaty, T., Al-Suwaidi, A. and Shaheen, M.: Increasing Well Life Cycle by Eliminating The Multistage Cementer and

Utilizing a Light Weight High Performance Slurry, paper SPE 53283 presented at the 1999 SPE Middle East Oil Show and Conference in Manamah, Bahrain, 20-23 February.

Nelson, E.B. et al.: Well Cementing, TSL-4135/ICN-01557200, Schlumberger Educational Services, 1990. Nelson, E.B., and Casabonne, J.M.: New Method for Better Control of Cement Performance in High-Temperature Wells,

paper SPE 24556 presented at the the 1992 SPE Annual Technical Conference and Exhibtion of the Society of Petroleum Engineers held in Washington, DC, 4-7 October.

Tanner, C.H. and Harms, W.M.: Unique Ultra Light-Weight Cement Slurry Compositions for Use in Unique Well

Conditions, Laboratory Evaluation, and Field Performance, paper SPE 11486 presented at the 1983 SPE Middle East Oil Technical Conference in Manamah, Bahrain, 14-17 March.

Sauer, C.W. and Landrum, W.R.: Cementing-A Systematic Approach, JPT, 2184-2196, December 1985. Sasaki, S., Kobayashi, W., and Okabayashi, S.: Effects of Various Factors on Thickening Time and Strength of Silica Cement

Under High Temperature, paper SPE 15335, Unsolicited, February 17, 1985. Smith, R.C.: Successful Primary Cementing Can Be a Reality, JPT, 1851-1858, November 1984. Stange, A.F.: Successful Cementing Procedure Developed for Mobile Bay, paper OTC 6040 presented at the 1989 Offshore

Technology Conference held in Houston, Texas, May 1-4. Abbreviations BHST : Bottom hole static temperature BWOC : By weight of cement Gps : Gallons per sack Hp : Horse power Ibpg : bounds per gallon ROP : Rate of penetration TD : Total depth UCA : Ultrasonic cement analyzer YP : Yield point SI Metric Conversion Factors in. 2.54* E02 = m (oF-32) / 1.8* E+00 = oC ft 3.048* E01 = m gal 3.785 412E03 = m3 lbm 4.535 924E01 = kg psi 6.894 757E-03 = Mpa lbm/gal 1.198 26E-01 = S.G bbl 1.58987 E-01 = m3

*Conversion factor is exact

16 IADC/SPE 135183

Appendix A: Criteria in Basic Best Cementing Practices Recommended Operational Practices Decision Appendix A describes the detail regarding the operational practices for each proposed well section and is considered by the authors as cementing best practices. These details are the factors that are considered in our optimum design. General

It is desired to batch mix cement slurry when possible for accurate density control. Adjusting drilling fluid properties for primary cementing as shown in Table A.1 is a good practice. Installing one centralizer every third joint in casing-casing annulus to surface is recommend. This might be optimized

based on logs run in the field. Installing a rigid centralizer in the casing-casing annulus just above previous casing shoe might aid in improving cement seal in the casing-casing annulus.

Having optimized cementing pump rate is important (6-8 bmp). However it is some time necessary to pump at 4 bmp in weakly consolidated formation in order not to fracture the formation while cementing. However the lower limit of having low pump rate is gas channeling problems.

It is always a good practice to confirm pressure rating for differential valve (DV) packers and liner top packers before their use.

It is a good practice to set a guideline for circulation time through DV tool prior to nipping down blow out preventer (BOP) stack to set casing slips or pump next stage.

It is important to know how long to wait for the cement to develop adequate compressive strength for the required operation as follow:

o Pipe support and zonal isolation: 100 psi. o Drilling out: 500 psi. o Perforation:

Bullets: 500 psi. Hollow carrier or expandable jets: at least 2000 psi.

o Whipstock plug: it is desired to be harder or close to the formation. If not then at least 2,500 psi. Liner Operations

1. Pump enough spacer and cement slurry. 2. Pay attention to difference in temperature in case of long liners. Compressive strength of 500 psi is required at the top

of the liner. 3. After releasing from the liner hanger, POH ten stands or above the top of the cement slurry and slowly reverse

circulation to clear drill pipe. 4. Close in the well with pipe rams and apply pressure in TCA. 5. When RIH with bit to drill top of liner, if no solid cement can be observed within 15-20 feet on TOL then wait for

longer time for cement slurry to develop the required compressive strength. It should be noted that having soft cement at the top of the liner can be due to contaminants which may not indicate cementing failure. That is why step # 1 is important to minimize this problem.

Plug Operations

1. Select depth of the plug from logs and drilling rate curves. For kickoff plugs, it is recommended to choose sand or lime that has fast drilling rate. Avoiding hard formation if possible is important to enhance the success of side track drilling.

2. Adjust drilling fluid properties as shown in Table A.2. 3. Designing cement plug slurries should also consider fluid loss, rheology and gas migration properties for good

performance in the field. 4. The volume of spacer fluid for plugs should be in the range of 500-800 ft of annulus volume. 5. Thixotropic cement slurries are desired to avoid falling into lower density fluid. 6. The cement slurry should be pumped at slow rate. 7. It is recommended to rotate drill pipe while pumping spacer fluid and cement slurries and not to reciprocate. After

placement, the pipe should be POH slowly. 8. It is a good practice to centralize the pipe string to improve drilling fluid removal. 9. Placing a viscous pill below the plug depth is a good practice.

Recommended Spacers Decision When the cement slurry becomes contaminated with drilling fluid (oil or high chloride concentration drilling fluid), severe gelation occurs resulting in possible premature setting of cement slurry and slurry failure. So a spacer fluid is required to be placed between the drilling fluid and cement slurry to eliminate this problem and to improve cement slurry placement operations. At high temperature (higher than 300 F) it is important for the spacer fluids to have the following properties:

IADC/SPE 135183 17

1. Stability with minimum settling at downhole conditions. 2. Compatibility with drilling fluid. 3. Compatibility with cement slurry. 4. Good fluid properties such as rheological and fluid loss. 5. Good volume displacement; 500 to 1000 ft of annular space or a volume that enables 5-10 minutes contact time.

The spacer density should be adequate to maintain well control and displacement. Ideal spacer density should be midway between drilling fluid and cement slurry densities or at least 0.5 lb/gal heavier than drilling fluid. Proper cement slurry design should consider bottom hole temperature, bottom hole pressure, hole and casing sizes and required thickening time for cement placement. Table A.3 shows an example of a spacer formulation. Compatibility tests should be done with drilling fluid, cement slurry and spacer fluid to ensure that their mixtures will not result in premature setting of cement slurry. Tables A.4-6 show compatibilities test results of spacer and drilling fluids. Drilling fluids with good filter cake properties are desired to improve cementing operations. Drilling fluid should be circulated and conditioned prior to cementing. Otherwise, static drilling fluid will thicken and will be difficult to be displaced by the cement slurry. Chemcials such as phosate, lime, sodium bicarbonate or a dispersant can be added to water spacer to be placed ahead of the cement slurry. Chemicals such as ferrochrome lignosulfonate and their salts of lignosulfonate acids should not be used in spacer formulations because they retard (delay setting) the cement. Water wetting surfactants are needed when using oil based drilling fluid. It is always a good practice to water wet the formation to improve cement formation bonding. Spacers should be compatible with mud and cement slurry. Spacers are said to be compatible if they do not change the cement slurry and drilling fluid properties much such as viscosity alternation and solids settling (Garvin and Robert, 1972). When using oil based drilling fluid, it might be required to use several spacers for successful cementing jobs. Barite or equivalent weighting materials can be used to ensure that Equivalent Circulating Density (ECD) does not fall below formation pore pressure. Oil based fluid is pumped first to displace the oil based drilling fluid out of the hole. Then water spacer is pumped to displace the oil based fluid. If the well is horizontal then additional spacers might be required such as water fluid spacers with surfactants to break down any immobile drilling fluid filter cake. The final spacer (in vertical or horizontal well) will be a water based spacer that has mutual solvent to water wet the formation for improved formation cement bonding, McPherson (2000). Recommended Cement Formulation Decision Cement Additives Lignosulfonate and some carbohydrate derivatives such as xanthan gum, cellulose and polyanionic cellulose are common retarders. Table A.7 shows a complete list of retarders that can be used with cement slurry to increase pumping time. Cement slurry accelerators have the opposite functions of retarders they are used to accelerate setting of cement slurries. They are used in low temperatures or in surface jobs. Table A.8 shows a complete list of cement accelerators. Viscosity of cement slurry also affect pumping properties, at high temperature the viscosity will be reduced which might lead to solids settling. To solve this problem, additives for viscosity control are used, Table A.9. Dispersants are used with cement slurry to improve the rheological performance especially at higher densities without the use of additional water, Table A.10. Expansion additives (for example CaO or MgO) are used to minimize shrinkage during cement slurry setting. The expansion additives are effective when bottom hole temperature is greater than approximately 300 F. Fluid loss additives are used to minimize hydration of water sensitive shale, to maintain the cement slurry water for the hydration process, and to minimize bridging in wellbore Table A.11. In case of cementing shaly formations, it is not recommended to use sodium chloride and potassium chloride because of their effect on cement slurry such as flash setting. Ammonium salts of aliphatic tertiary amines can be used with cement slurry in water sensitive shales. For wells that show high gas migration potential we can use latex additive. Latex is a copolymer of AMPS, N-Vinylacylamide and acrylamide, Fink (2003). Flexible Cement for Expandable Casing or Milling Operations Long term durability of cement is an important character that needs to be considered when cementing expandable casing applications. Milling the cemented casing also could introduce problems to conventional cements. Stress modeling shows that conventional cement can fail due to pressure and temperature cycles, El-Hassan et al. (2005). Throughout the life of the well, the cement sheath is exposed to changes in the down hole conditions due to:

Opening window for multilateral wells Temperature increase in the production process Pressure increase in the well bore pressure due to gas production Change of drilling fluid after drilling to a lighter completion fluid Changes of drilling fluids density while drilling different formations Stimulation treatments Formation loading (creep, compaction, faulting) Hydration of cement.

18 IADC/SPE 135183

All these variations in down hole conditions lead to stresses induced in the casing and in the formation and consequently in the cement sheath. The usual perception for judging the mechanical properties of cement is to look at the compressive strength, the higher the number the better the cement is. However, due to the above conditions, the cement failure would occur mostly in tension, debonding. Flexibility is achieved by the relative decrease of the Youngs modulus value compared to the conventional system; therefore, the cement sheath can withstand more stresses without destroying the integrity of the set cement matrix. The magnitude of the Youngs modulus is inversely proportional to the concentration of the flexible additives; thus, the higher the concentration of the flexible additives the higher the elasticity of the set cement, El-Marsafawi et al. (2006). Flexible additives such as latex can be used to formulate cements for expandable casing or for casing that will undergo milling operations to prevent formation of cracks and to improve wellbore isolation. Acidizing Acid solubility tests were conducted by placing samples of regular and flexible cements in 5 wt% HCl solutions. Samples were collected over time and were analyzed for key cations. The concentrations of calcium and total iron in solution as a function of time were measured. It is evident from these results that the acid leached more calcium and iron from regular cement than those obtained with flexible cement. In addition, the porosity of regular cement is slightly higher than the flexible cement. This means that the surface area exposed to acid is larger in the case of regular cement, El-Marsafawi et al. (2006). Flexible additives such as latex can be used to formulate cements slurries for wells that are planned for acidizing. Low Density Cement Low density cement slurries are used to reduce the hydrostatic pressure on weak formations and to cement lost circulation zones. Examples of low density cements are water extender cements, foam cements and hollow microsphere cements. Water extender cements are limited in density to nearly 11.5 lbm/gal (Kulakofsky and Vargo, 2005). Cement fallback often occurs and top of set cement can be hundreds of feet below the ground level because the formations cannot withstand the hydrostatic load exerted by water extender cements even if full circulation is maintained to surface and cement returns are noted (Harms and Febus, 1985). Sulfide containing water can then corrode the uncemented casing resulting in expensive surface casing remedial treatments (Tanner and Harms, 1983).

Water extender cements can be used in multistage operations, however multistage cementing is limited in their success. Stage tools can fail resulting in remedial operations such as perforation and squeeze jobs, Mukhalalaty et al. (1999). Furthermore, the complexity of multi-stage installation is another potential reason to failure. The elimination of stage tools can lead to reduction in cost and rig time, which is important in drilling operations. In addition, stage tools are considered weak points and not good for long term seal as they may result in failure problems and casing leaks.

The only two types of low density cements that can be used to avoid using multistage tool failure are foam cement and hollow microsphere cement, Al-Yami et al. (2010).

Cementing High Temperature Wells with Long Liners Retarders are cement additives whose function is to retard, or delay the setting of cement slurries. For a well whose temperature is about 125 F or less, no retarder is needed to be added to the cement slurry when API class H or G is used, Brothers et al. (1991). However, as temperature increases, the hydration process of C3S increases and, hence, the thickening time decreases, Bensted (1991).

Some types of retarders tend to reduce the compressive strength of set cement, Sasaki et al. (1985). Hence, a well designed retarder needs to increase the thickening time without having a significant effect on the compressive strength. Similarly, fluid loss control can be affected by the addition of retarders, especially at high temperatures (Eoff and Buster, 1995).

Cement slurries can easily be over retarded for top of cement (TOC) conditions because API thickening time test procedures are designed to determine slurry pumpability at the bottom hole circulation temperature (BHCT). For cementing casing jobs this does not represent a problem because drilling operations will continue as soon as the cement develops compressive strength at the bottom, so no need to consider the top conditions of the cement. However, when cementing liners, the cement must develop compressive strength at the top of the liner before drilling is resumed. If drilling is resumed before the development of compressive strength at the top of liner, severe lost in rig time and cost will result. In addition, it will be difficult to fix the damaged cemented upper interval. On the other hand, if drilling is paused in order to obtain the compressive strength required at the top of the liners, this will result in excessive delays from long waiting on cement (WOC) time. This occurs if the cement slurries were not designed properly, Al-Yami et al. (2007). When designing cement slurries, accurate measurement of the static temperature of the top of liner and the bottom is important because small variations of temperatures, as small as 10 F, have great effects on thickening time. In addition, it is vital that optimum designed cement slurries are used to achieve adequate slurry placement time and acceptable short WOC time (Nelson and Casabonne, 1992).

Using improper cement slurries can lead to cement over-retardation. Especially if there are large temperature differences between the upper and lower portions of the cement column. In this case, the cement slurries have retarder concentrations that are developed for the bottom interval which has the highest temperature. It is difficult to obtain good compressive strength at

IADC/SPE 135183 19

the top of liner when there are large temperature differences between the upper and lower intervals of the cement column (Nelson and Casabonne, 1992).

The cement slurries should meet the following requirements, Al-Yami et al. (2007): 1- The thickening time must be sufficient to allow proper slurry placement. 2- Rapid compressive strength development at the top of the liner and the bottom. 3- The slurry must be easily mixable and must not exhibit free water or settling tendencies. 4- A fluid-loss of 100 ml/30 min.

For non-latex cement slurries, the following are recommended: 1. Ethylene glycol and calcium lignosulfonate retarders should not be used. Compressive strength was not

developed after WOC for more than 24 hours. 2. The following retarders combination are recommended: Sodium lignosulfonate, ethylene glycol and calcium lignosulfonate. Mixture of sodium salt and alicyclic acid with aminated aromatic polymer and sodium tetraborate Sulfamethylated lignin and inorganic salt

For latex cement systems, the following can be concluded: 1. Sodium tetraborate and sodium lignosulfonate combination of retarders should not be used since no compressive

strength was developed after WOC more than 24 hours. 2. Acrylic polymer, modified lignosulfonate and inorganic salt provided high sensitity to shear and only 613 psi

after WOC for 24 hours. 3. The following retarders combination are recommended: Blend of salt and organic acid. Aromatic polymer derivative and blend of salt and organic acid. Sodium salt of alicyclic acid and aminated aromatic polymer.

Cement Kick off Plugs Directional drilling makes it possible to drill multilateral wells into different parts of a reservoir from a single wellbore. Many directional wells are drilled to reach reservoirs inaccessible from a point directly above because of surface obstacles or geologic obstruction. Wellbore sidetrack operations with hard cement plugs have been used for years. Placing the cement slurry in the borehole to develop high compressive strength helps assure a successful sidetracking technique. The hardened cement plug when drilled deflects the bit away from the current borehole, starting another open hole section. Conventional cement formulations for sidetrack kickoffs usually fail when the ROP (Rate of Penetration) for the cement plug is much greater than the ROP in the formation. Sidetracking failures, in building kickoff angles, results in operational delays and cost overruns. High sonic compressive strength cement systems with low ROP should be designed and developed specifically for side tracking operations, Al-Yami et al. (2008) The following can improve directional drilling operations in open holes:

1. Using a blend of silica flour, expansion additive and or fracturing proppants with conventional additives is the best solution to achieve good sidetrack cement slurry at temperatures greater than 250F to avoid rig lost time due to failures associated with conventional methods, Al-Yami et al. (2009).

2. Manganese oxides are recommended to be added to neat cement at temperatures less than 250F. 2. Following proper guidelines in spotting sidetrack cement slurry are important. Examples of the guidelines are

spotting viscous fluids before cementing will help to minimize cement contaminations. It is also recommended to pump open hole volume and 50% excess to compensate for drilling fluid contamination.

3. It is essential to pilot test any cement slurry to ensure good compressive strength build up prior to drilling. 4. It is recommended to wait on cement slurry for 24 hours before drilling.

Gas Wells with Extreme Abnormal Pressure Gas Migration through cement columns has been an industry problem for many years. The most problematic areas for gas migrations occur in deep gas wells. To control gas migration, cement densities required to successfully cement the zone could be as high as 23 lbm/gal (Pounds per Gallon). As the cement slurry sets, hydrostatic pressure is reduced on the formation. During this transition, reservoir gases can travel up through the cement column resulting in gas being present at the surface. The permeable channels, from which gas flows, cause operational and safety problems at the well site. Latex additives may be required to prevent gas/fluid migration during the setting of cement slurry. For wells that have considerable fluid or gas flow, latex is required. On wells with drilling fluid weights equal to or greater than 18 lbm/gal, latex is required. For wells with drilling fluid densities that are less than 16 lbm/gal, conventional dry fluid loss additives are recommended. These wells with high drilling fluid density usually have had considerable flow from the formation. Expanding cement additives are needed for wells that will be drilled with drilling fluid densities that are less than 2 lbm/gal from the previous hole section. The reduction of pressure from reducing the drilling fluid density can cause the casing to shrink. This shrinkage can cause the cement-casing bond to break which will allow gas flow. This situation is more likely to occur as the depth increases. Expanding additives are also recommended for cementing gas producting formations at depth greater than

20 IADC/SPE 135183

10,000 ft, Jennings et al. (2003). The most common problem associated with high density cement slurries using hematite is settling. Some times, settling can be controlled by anti settling chemicals in the lab. However, controlling hematite settling in the field is not ensured. Several wells experienced bad cementing at the lower section of the well. Pressure testing showed a leak at the bottom of the cemented casings. In addition, cement settling is observed in the mixing tanks used to pump the slurries. The high density cement slurry problem was due to hematite settling in the lower section. The cement additives are designed to react with the cement and not the high concentration of settled hematite at the lower section. This explains the good upper cemented section and the bad cemented section at the bottom, which caused fluid immigration. Using silica sand, silica flour, hematite, manganese tetraoxide with expansion additive showed the best performance in terms of gas migration problems, fluid loss control and minimum settling, Al-Yami et al. (2009). All cement formulations were designed to have the properties listed in Table A.12. Low and high temperature retarders were used to slow down the setting of the cement and fluid loss additives to maintain the water within the cement slurry. Gas block (latex) was used to coat the cement and aid in gas migration prevention. CO2 Injection Well It is well known that carbon dioxide-laden waters can destroy the integrity of cements, Nelson et al. (1990). The result is removing of cementitious material from the cement matrix, an increase in porosity and permeability, and a decrease of compressive strength. Formulating CO2 resistance cement is an ongoing research. Different cement blends have been proposed for CO2 environment. All CO2 cement proposed slurries should have a blend of cement that contains less than 30% Portland cement and other solids particles selected based on optimum particle size distribution for minimum permeability. Silica source should also be added for enhanced cement compressive strength stability. No special additives are required to obtain acceptable thickening time, rheology, or fluid loss properties, Benge (2005).

Table A.1: Desired mud properties for primary cementing jobs Property Desired

YP maximum 10 PV maximum 20 FL maximum 15 cm3/30 minutes

Gel Strength flat profile in the 10 sec/10 min

Table A.2: Desired mud properties for cement plugs Property Desired

YP 1-5 PV 1-20

Funnel viscosity 45-80

Table A.3: An example of a water spacer formulation Formulation Properties Fresh Water PV: 25-30 Bentonite YP: 20-25 XC-Polymer Gel: 4/12 PAC-R Filtrate: 6-8 Caustic Soda pH: 9-9.5 Weighting Material (barite or calcium carbonate or hematite or manganese tetra oxide)

IADC/SPE 135183 21

Table A.4: Spacer rheological properties Information Viscometer reading, RPM

Spacer at 153 pcf Temperature, F 300 200 100 60 30 6 3 100% spacer 80 222 169 108 78 52 21 15 100% spacer 100 125 98 66 50 35 15 11

Table A.5: Mud rheological properties Information Viscometer reading, RPM

Mud at 150 pcf Temperature, F 300 200 100 60 30 6 3 100% Mud 80 118 86 52 36 23 11 10 100% Mud 100 68 53 38 30 24 18 20

Table A.6: Mud-spacer mixture rheological properties Information Viscometer reading, RPM

Mud-Spacer Mixture Temperature, F 300 200 100 60 30 6 3 75%Mud+25% spacer 190 97 72 46 34 25 15 14 50%Mud+50% spacer 190 112 85 56 43 32 18 18 25%Mud+75% spacer 190 144 104 76 59 44 26 23

Table A.7: Cement retarders Compound Class

Copolymer of isobutene and maleic anhydride Amino-N-([alkylidene] phosphonic acid) derivatives Alkanolamine-hydroxy carboxy acid salts such as tartaric acid and ethanolamine Phosphonocarboxylic acids Dicyclopentadiene bis(methylamine) methylenephosphonate Lignosulfonate derivatives Carbohydrated grafted with vinyl polymers carboxymethyl hydroxyethylcellulose Wellan gum1 Borax based Carrageenan Polyethylene amine derivatives and amides Copolymers from maleic acid, of 2-acrylamido-2-methylpropane sulfonic acid and others2 Ethylenediamine-tetramethylene phosphonic acid, polyoxyethylene phosphonic acid, or citric acid3 Scleroglucan Polyacrylic acid phosphinate3

1) Co-additives for retarded formulations 2) Calcium-sodium-lignosulfonate is the best retarder for bentonite cement slurries 3) High alumina cement

22 IADC/SPE 135183

Table A.8: Cement accelerators Compounds

Propylene carbonate1 Sodium and calcium chlorides2 Aluminum oxide and aluminum sulfate Sodium sulfate Calcium chloride 2,4,6-Trihydroxybenzoic acid and disodium 4,5-dihydroxy-m-benzenedisulfonate2 Ester of formic acid and formamide Monoethanolamine, diethanolamine triethanol amine

1) Has thixotropic properties 2) Chloride free

Table A.9: Viscosity control additives Compounds

Latex Scleroglucan1 Calcium lignosulfonate2 Phenol-formaldehyde resin modified with furfuryl alcohol Hectorite clay3 sulfonic acid copolymer, castor oil

1) High temperature viscosifying additive 2) Also work as retarder 3) For thixotropic cement

Table A.10: Dispersants Polyoxyethylene sulfonate1 Acetone formaldehyde cyanide resins Polyoxethylated octylphenol2 Copolymers of maleic anhydride and 2-hydroxypropyl acrylate Allyloxybenzene sulfonate or allyloxybenzene phosphonate3 Ferrous lignosulfonate, ferrous sulfate, and tannic acid Alkali lignosulfonate4 Acetone, formaldehyde polycondensate5 Sulfonated napthalene formaldehyde condensate Sulfonated indene and indene-cumarone resins Melamine sulfonate polymer, vinyl sulfonate polymer, styrene sulfonate polymer Polyethyleneimine phosphonate Casein with polysaccharides

1) Used for squeeze cementing 2) Nonionic surfactant 3) As copolymer with different vinyl monomers 4) Biodegradable 5) For dispersing silica fume

IADC/SPE 135183 23

Table A.11: Fluid loss additives for cements Water solube polymers Gilsonite1 AMPS based fluid loss additives Styrene butadiene latex2 Anionic aromatic polymers3 Polynaphthalene sulfonate and acrylic terpolymer Polyvinylacetate4 Copolymers of acrylic acid and long side acrylic esters Hydrophobically modified hydroxypropyl guar

1) Density reducer too 2) Has thixotropic properties 3) Low bottomhole temprature 4) With sulfonated polymer and surfactant

Table A.12: Properties required to prevent gas migration

Cementing Requirement Range

Thickening Time, hrs 7-9

Fluid Loss (ml/30 min.) < 50

Free Fluid, % 0

Rheology, YP >1

Sonic Strength (50-500 psi) < 1 hour

Settling Density Difference < 5 pcf

Fluid Migration (time for gas break through) > 5 hours

Proof of Concept of the Proposed Decision-Making Model

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