Studying of Shale Instability Problems with Treatment in Tanuma and Zubair Formations of East Baghdad Oilfield

Abstract


Introduction
Wellbore stability is a critical concern in drilling operations.Shale instability occurs when shale formations become unstable and eventually break apart, falling into the wellbore.This can lead to several problems, including wellbore collapse, stuck pipes, and lost circulation.More than 90% of wellbore collapse occurs in shaly formations.Hard brittle shale accounts for 67% of these collapses.This is because hard brittle shale is more likely to break apart than soft shale (Kanfar et al., 2017;Asaka et al., 2020).This can cause significant drilling problems including tight holes, stuck pipes, lost circulation, and inadequately cleaned holes.These shale difficulties can range in complexity from tiny discomfort with modest cost increases to major obstacles with large negative outcomes, such as loss of the drill string or complete well failure.
Shale deposits are extremely fine sedimentary rocks with a high concentration of clay particles.They are mostly made of clays, silt, water, and small quantities of quartz and feldspar.Shale rock is a sedimentary rock with limited permeability and high degrees of plasticity, making it more prone to borehole instability than other rock types (Javadpour, 2009).Shale failure may occur due to the chemical interaction between the drilling fluid and the shale rock or due to the mechanical effects resulting from unbalanced stresses between the wellbore and the formation being drilled (Zimmerman et al., 1987).Understanding the reasons and mechanisms of shale instability is therefore critical for developing effective wellbore stability control measures.For the chemical reaction, shale formations can absorb the existing water in the drilling mud causing a swelling of shale particles.If there's a great deal of water, shale cannot retain its particles together and they will fall apart into the well.Another inherent issue is that shale instability due to chemical reactions is time-dependent, meaning that it may not be visible on the first day of drilling, but it can become evident after the drilling has been carried out for several days (O'Brien and Autin, 1985).
Many researchers have been focused on understanding the causes and mechanisms of shale instability and developing effective management strategies (Wang and Zhang, 2019).Laboratory evaluation of drilling fluid performance is utilized to select the mud type and its chemistry (Jain and Mahto, 2017).This includes the development of novel drilling fluids, such as non-aqueous drilling fluids, and the optimization of drilling parameters, such as the mud weight and drilling rate, to reduce the risk of shale instability.Additionally, advanced analytical techniques, such as XRD and scanning electron microscopy, have been used to gain insights into the microstructural and mineralogical characteristics of shale formations and their role in shale instability.According to research conducted by Alshibli and Alhaleem (2022) and Awadh et al. (2014), shale-fluid interaction Awadh et a., 2019;Awadh et al., 2021) is to blame for well-bore instability, downhole issues, and higher well costs discovered in the Zubair Oilfield's investigation of the Tanuma and Zubair formations.Shale instability is mitigated through the use of laboratory tests and polymer muds containing inorganic inhibitors.Drilling mud development concerns and expenses related to shale instability may be mitigated as a result of the findings.
Historically, different scientists provided diverse viewpoints, ideas, and recommendations to explore shale formation instability.Weyl (1960) argued that shale instability is principally driven by high pore pressures generated by fluid invasion.The existence of tiny pores, cracks, and fractures within the wellbore permits fluid to flow through and inside the shale rock, leading to its swelling.The swelling, in turn, raises the pore pressure, which causes the cementation bonds between particles to break.The presence of these tiny openings is a key factor contributing to both wellbore failures and shale stability issues (Khosravi et al., 2016;Hangx and Bruhn, 2017).
The identification and categorization of shale reactivity level can be achieved through the practical testing method of cation exchange capacity CEC.The use of methylene blue solution is a method for measuring shale reactivity by determining CEC, as stated by Stephens et al. (2009).Highly reactive shale has a CEC of more than 20 (meq/100g), whereas moderately reactive shale has a CEC between 10 and 20 (meq/100g).However, even low CEC levels (10 meq/100g) might be troublesome if active clays are present, since these clays can cause shale breakup and swelling (Garcia et al., 2013;Alshamy and Almahdawi, 2021).
According to Theis (1964), shale instability is generated by the interaction of drilling fluids with shale formations.To address this issue, researchers suggested using low-permeability shale barriers or using pressure control methods during drilling operations.(Klotz, 1962;Gardner, 1975) stated that shale instability is generated by the interaction between drilling fluids with shale formations.Some researchers (Naylor and Mukherjee, 1980), recommended the use of modified drilling muds, like oilbased fluids, be used to limit the contact between drilling muds and the formations of shale.Additionally, laboratory experiments were conducted to investigate the reasons for shale instability, including testing the effects of different types of drilling fluids on shale formations and evaluating the role of pore pressure and temperature on shale instability.Alwassiti et al. (2019) performed laboratory research to look into the reasons for shale instability by studying the impact of various kinds of drilling muds and assessing the function of pore pressure and temperature on shale instability.They improved shale stability by incorporating chemicals into the drilling mud.They employed two types of drilling fluids, API and polymer, with five additives (KCl, NaCl, CaCl2, Na2SiO3, and Flodrill PAM 1040) in varied quantities (0.5, 1, 5, and 10) wt% and immersion times (1, 24, and 72 hours).The results reveal that adding 10% Na2SiO3 to API drilling fluid results in a high percentage of shale recovery (78.22%) while adding 10% Na2SiO3 to polymer drilling fluid results in the highest percentage of shale recovery (80.57%).Hadi et al., 2022.The study develops cost-effective models for future well planning in Iraqi oil fields by using input data like mud density to determine the rheological properties of water-based drilling fluids through regression analysis and artificial neural networks.Shaker and Hadi (2022) Presented research on the East Baghdad field of formations of sandstone and oil shale formations in Nahr Omar and Zubair, where the research compared the results from two wells using three distinct AI estimation and comparison strategies: artificial neural networks, fuzzy inference systems, and genetic algorithms.By optimizing drilling parameters and using the established model to anticipate penetration rates, future wells in the East Baghdad oil field can be drilled more efficiently and at a lower cost.
The objective of this study is to develop new muds that can be used to reduce the shale reactivity, thus enabling safe drilling operations, and minimizing the associated costs.This can be conducted by implementing experimental work to investigate two key aspects related to shale examination its physical properties and its reactivity when it's exposed to fluids.A range of description tests were also conducted to obtain a better understanding of the shale's characteristics and structure.The scanning electron microscope (SEM) technique also examined the shale samples to their micro-fractures.The cation exchange capacity (CEC) test was then used to enhance the category of the shale reactivity level for both the Tanuma and Zubair formations.Furthermore, a Capillary Suction Timer (CST) test was conducted with varying concentrations of KCl to select the shale inhibitors and the optimum additives for preventing shale swelling.Finally, the proposed muds were evaluated for shale-fluid compatibility utilizing shale-fluid compatibility tests such as the Linear swelling test and hot rolling procedures to determine the efficiency of the chosen additives in minimizing the shale instability.

Area of Study
East Baghdad oilfield (EB oil field) is one of the important giant fields in Iraq; This has dimensions of approximately 120x10 km, elongated in a NW-SE direction, with its central part in northern Baghdad city.EB oil field has been partitioned into six geographical regions.These regions are, listed in order from the northwest to the southeast; the north extension area, Al-Taji area, Al-Rashdiya area, urban area, south 2 area, and south 1 area.As illustrated in Fig. 1 ( FWR, 2020).
The field is composed of several formations including three major formations (Tanuma, Khasib, and Zubair ).Based on the final well report (FWR), oil and gas production commenced from these three formations in Jan 1980, Fig. 2, shows the stratigraphic column of the EB oil field in which the production section is started from Tanuma Formation to Zubair Formation.Drilling reports showed that most of the wellbore instability problems occurred in the intermediate and production sections, which are the 12 ¼ʺ and 8 ½ʺ sections (Fig. 3).According to the findings, Tanuma and Zubair formations are the most unstable shale horizons in these sections they are problematic formations during drilling operations.These formations are normally exposed to a range of problems, including swelling, sloughing, caving, cementing problems, and casing landing issues that can result from the interaction between the drilling fluids and the formation.The Zubair Formation in the EB oilfield is found at depths ranging from 3044.3 to 3444 m.It is regarded as one of the most difficult formations to drill wells in this field.The majority of Zubair shale unit drilling difficulties include caving, sloughing, swelling, cementing problems, and casing landing problems induced by drilling mud contact with the formation (Alwassiti et al., 2019).
These findings underscore the need to focus on these formations and their geomechanical properties and chemical effects with drilling fluids to reduce the risk of wellbore instability and associated costs.

Experimental Work of Shale-Fluids Interactions
The X-ray fluorescence (XRF) test aims to analyze the chemical compositions of Tanuma and Zubair shale.XRF analysis is a powerful method for determining the elemental composition of substances.X-ray diffraction (XRD) is used to determine the mineralogy of the shale formations, especially Zubair and Tanuma, by identifying the presence of clay and non-clay minerals.XRD can be used to classify the rocks into quatzose, feldspthis, or micaeous.The SEM technique is employed to examine the shale structure, analyze its substructure morphology, and identify micro-fractures, microcracks, and micro-pores, which provide insights into the need for specific mud chemicals for shale inhibition.
Additionally, the level of shale reactivity can be assessed using the CEC and the CST is a widely used method to evaluate the flocculation and dispersion of shale.It is particularly useful for determining the effectiveness of shale inhibitors and as well as calculating the weight % of a particular salt as an inhibitor.The CST test includes maintaining constant ingredients and mixing time while altering just the chemical concentration.The duration of the test depends on various factors, including the type of solids, pH, slurry content, salinity concentration, and the properties and concentration of the deflocculant and polymer utilized (Stephens et al., 2009).Finally, the LSM and hot rolling techniques will be used to evaluate two polymer mud systems for each formation.To determine the effectiveness of selected shale inhibitors, It is critical to use the appropriate mud to assess the hydrated or dehydrated (swelling) shale.The LSM is a viable approach for analyzing shale reactivity since it measures the percentage of clay swelling with time and the tendency of shale samples to undergo hydration or dehydration when in contact with the mud.The swelling measurement obtained indicates the reactivity of the shale to the particular mud utilized (Abbas et al., 2018).The research aims to identify and validate the required additives and mud chemicals for water-based mud, including the optimal concentration and types of shale inhibitors.

Results and Discussions
This section presents the results of investigating the Tanuma and Zubair shaly formations and determining the performance of drilling fluids to address this issue of shale swelling.Various tests were conducted on shale samples, and the results were examined and discussed.Based on the findings, two water-based mud (WBM) formulations were developed, each containing different shale inhibitor agents.The effectiveness of these formulated muds in preventing shale swelling was evaluated using the linear swelling meter (LSM) test.Additionally, the shale erosion technique, known as hot rolling, was employed to verify the efficiency of the mud to shale.

Characterization of Shale
Samples were taken from various depths of well Z in the EB oil field were visually inspected and analyzed with a traditional microscope.The visual representation of Fig. 4. illustrated that Tanuma Formation is primarily composed of shale (0-90%) and silt (0-10%).The shale is characterized as greenish-grey and olive-gray, slightly hard, fissile, and exhibits calcareous properties (Fig. 4.) The visual illustration in Fig. 5 shows that the Zubair Formation is made up of shale (0-70%), silt (0-20%), and sand (0-10%).Greenish grey-grey, dark and light grey, fissile, moderately hard, occasionally sub-fissile, glauconitic, and non-calcareous.

Analysis of Shale Composition and Configuration of the SEM Test
Microfractures in shale rocks can contribute to the fluid flow and affect the stability of wellbores.Pore pressure buildup in shale formations can also contribute to wellbore failures (Khosravi and Montgomery, 2016).Understanding the role of pore structure and permeability is essential for shale stability (Xiong, 2019).The shale structures, including micro-fractures, micro-cracks, and micro-pores, were examined using SEM for both the Tanuma and Zubair formations.The SEM images indicated the presence of a large number of micro-fractures and pores in both formations, Tanuma shale (Fig. 6) contains a significantly higher number of micro-fractures and pores if it's compared to the Zubair shale unit (Fig. 7).The micro-cracks and fractures in the Tanuma shale nuit (Fig. 6) were observed to be larger, with lengths ranging from 5 and 30 μm and widths ranging from 1.5 and 10 μm, than the Zubair shale unit (Fig. 7) Micro-cracks and pores that ranged between 9 and 20 μm in lengths and 1 and 5 μm in width.

Cation Exchange Capacity (CEC)
According to the American Petroleum Institute (API) (2004) testing procedure, the CEC test, was conducted in this study on samples taking from Tanuma and Zubair formations.The results of Theis test revealed that the CEC value for Zubair shale unit is low, at 7 milliequivalents per 100 grams (meq/100gm), falling into the low reactivity category.Conversely, Tanuma shale displayed a moderate to high reactivity, with a CEC value of 15 milliequivalents per gram, indicating that it is more reactive than the Zubair Formation.

Capillary Suction Timer (CST)
Shale samples with varied salt amounts were evaluated to rectify the shale reactivity.The test was carried out in increments; with 1% KCl added at each stage, and the test was repeated to raise the KCl concentration.Table 1 presents the results of the CST conducted on samples of Tanuma and Zubair shale units.Distinct reactivity behaviors were observed for the Tanuma and Zubair formations when it's exposed to incremental steps of salt concentration and Deionized water (D.I water).The CST results obtained using D.I. water indicated a longer time for both formations.Notably, Tanuma's shale recorded a longer time of 355.3 seconds, which was higher than Zubair's shale (175.5 seconds).This serves as additional evidence of the Tanuma shale's tendency and response to the interaction with fresh water.Furthermore, the CST readings of Tanuma samples are consistently surpassed those of Zubair Formation throughout all stages.At 3% KCl, the Zubair Formation had the lowest CST time of 18.2 seconds.In contrast, the Tanuma Formation required 7% KCl before recording its lowest CST time of 25.6 seconds.The CST time for Tanuma Formation exhibited a notable increase upon further addition of KCl beyond the optimal point.On the other hand, at greater salt concentrations than the optimum KCl, the Zubair Formation remained rather stable.

Optimization of Drilling Fluid Performance
Testing the hydration or dehydration (swelling) of shale with the designated drilling mud is a necessary step when the shale formations are drilled.These tests assess the percentage of clay swelling over time and provide insight into the efficacy of the chosen inhibitor in managing shale swelling.Considering the findings from the CST test and the characteristics of the shale, the decision was made to create two variations of water-based muds (WBM) with different shale inhibitor agents.The aim is to mitigate the shale swelling in the formations of Tanuma and Zubair.The formulated muds were subjected to testing using the LSM to evaluate their interaction with shale.Subsequently, the effectiveness of the mud in preventing shale erosion was confirmed through a hot rolling test, which employed the hot rolling method.The initial polymer mud (WBM-1) was created using additives such as partially hydrolyzed polyacrylamide (PHPA) and gilsonite.The second polymer mud (WBM-2) incorporated a dispersion and hydration suppressant, specifically polypeptides, as its primary component.The selection of the KCl percentage in both mud formulations was based on achieving the lowest capillary suction time (CST) values, as indicated in percentage of 7% was chosen, while for the Zubair Formation, it was 3%.Filtration controls and gilsonite were chosen based on the SEM results to effectively seal the micro-fractures and pores present in the shale rocks, while the addition of polymers aimed to mitigate shale disintegration.
The results of the study showed a consistent and immediate interaction between the shale and different muds, as indicated by the positive slope.Freshwater caused higher swelling rates compared to WBM-1 in both Tanuma and Zubair shale.In the case of Tanuma shale, the swelling ratio was 20.15% for the fresh water and 6.13% for the WBM-1.Similarly, for the Zubair shale unit, the respective ratios were 6.04% for fresh water and 3.01% for the WBM-1.A comparison between WBM-1 and WBM-2 also revealed higher shale swelling rates for WBM-1 in both shales.For the Tanuma shale unit, the expansion was 6.1% with the first mud and 3% with the second mud.In Zubair shale, the shale expansion was 3.01% with the first mud and 1.53% with the second mud, exhibiting distinct patterns of shale stabilization with each mud.
The shale in the Tanuma Formation is more active, ranging from moderate to high, compared to the Zubair Formation, which is relatively low to moderately reactive shale.Both formations exhibited the presence of microfractures and micropores.To maintain shale stability, it is recommended to add 7% KCl to Tanuma's drilling mud and 3% KCl to Zubair's drilling mud.By sealing the open structures in shale and introducing a polypeptide hydration suppressant, filtration controls are implemented to significantly reduce the risk of shale swelling.

Linear Swelling Test (LST)
The LSM technique was employed to conduct the swelling test, It entails measuring the free swelling of a reconstituted shale pellet after being exposed to fluid.The results present the swelling behavior of samples when it's subjected to different fluids.The obtained results provide valuable insights into the extent of swelling experienced by the samples under fluid exposure conditions as the percentage of swelling.In the beginning, the Linear Swelling Test (LST) was used to evaluate the efficiency of the chosen shale inhibitors and other additives.The WBM-1 was evaluated with freshwater mud for each of the Tanumah and Zubair shale units to determine the percentage and the level of shale swelling.The results revealed a positive slope, showing the presence of a consistent and immediate reaction between the shale and the freshwater mud used.
Figs.8 and 9 revealed that the freshwater mud (blue curve) exhibited a higher rate of swelling due to the absence of any polymer content in it, for both formations.In Tanuma shale status, the swelling ratio was 20.15% for freshwater mud compared to 6.13% for WBM1.Similarly, for the Zubair shale unit, the respective ratios were 6.04% for freshwater and 3.01% for WBM1; this is an indication of less swelling in the Zubair rather than Tanuma Formation.
Figs. 10 and 11 present the level for the Tanuma and Zubair formations of interaction with shale, respectively, as indicated by the low percentage of shale swelling for WBM2.
All the obtained results exhibited a positive slope, confirming a consistent and immediate interaction between the shale and drilling mud employed.Additionally, it was observed that WBM1 had a higher rate of shale swelling compared to the second mud (WBM2) in both Tanuma and Zubair shale units.
As depicted in Fig. 10 for Tanuma, both mud formulations exhibited a relatively positive stabilization after approximately 1 hour.During this period, the shale expanded by approximately 3.9% with WBM1 and 2.3% with WBM2.By the end of the test, the total shale expansion reached 6.1% with WBM1 and 3% with WBM2.In the case of the Zubair shale unit, as illustrated in Fig. 11, each mud demonstrated different behavior in terms of shale stabilization.Initially, there was an immediate reaction for WBM1 causing the shale to expand by 1.8% within the first hour.Subsequently, a stable expansion rate was observed, increasing to 1.21% and 3.1% by the end of the test.On the other hand, WBM2 exhibited a reactivity percentage (around 0.9%) during the initial half-hour of the test.The trend then stabilized until the end of the test, resulting in a 1.5% expansion.

Hot Rolling
The shale erosion test was conducted using a standard hot rollers oven to simulate the circulation of shale cuttings up the wellbore annulus, as reported by Friedheim et al. (2011).Testing was used to examine whether the prepared fluids would promote erosion on the shale samples.According to Abbas et al. (2018b), mud is considered safe if the shale sample demonstrates a high recovery rate when exposed to that specific mud.The shale erosion test results confirmed the findings of the LSM, with a low tendency for weight loss or dispersion.As shown in Fig. 12, WBM-2 exhibited a higher recovery percentage in both formations compared to WBM-1.In the Tanuma Formation, WBM-2 achieved a recovery rate of 91.2%, while reached 95.3% in the Zubair shale unit.Conversely, WBM-1 recorded recovery rates of 85.7% in the Tanuma shale and 90% in the Zubair shale unit.

Discussion
During the initial evaluation of the shale rock, there are noticeable differences between Tanuma and Zubair formations.Tanuma shale unit exhibits an olive-gray color with hints of green, indicating the presence of Chlorite, Kaolinite, and Illite.In contrast, Zubair shale displays a combination of dark and light gray colors, suggesting a carbonic environment due to its interbedding with reservoir layers.Both shale formations exhibit parallel laminae, with Zubair shale having a higher abundance compared to Tanuma shale.Furthermore, Tanuma samples exhibited decreased fissility, probably due to the presence of calcareous material, indicating a less strong structure.The hardness characteristics of both formations suggest the potential presence of Illite and mixed clay layers.Upon examining the SEM images, it is evident that both Tanuma and Zubair shales possess microfractures and pores within their structures, which can contribute to the shale instability issues by facilitating an increase in pore pressure.However, there are notable differences between the two shales in terms of the size and quantity of these microfractures and pores.Tanuma shale exhibits considerably larger and more abundant microfractures and pores compared to Zubair shale.This implies that Tanuma shale provides relatively larger pathways for fluid penetration compared to the Zubair Formation.
The reactivity of shale, as indicated by the CEC and CST tests, aligns with the findings from the XRD and XRF analyses.Zubair shale exhibits lower CST and CEC results, attributed to their lower clay mineral content.The CST technique validates and classifies the reactivity of shale.CST values greater than 170 seconds indicate dispersion of clay particles into the fluid due to osmosis within shale pores when tested with DI water; however, as KCl is gradually added, the CST measurements significantly decline until equilibrium between formation fluid and mud activity is reached.These findings imply that shale-chemical interactions take place in both strata, with Tanuma's shale exhibiting potential reactivity.When subjected to low salinity drilling muds, the salinity of water within shale pores, cation exchange capacity, and cation membrane efficiency (with microfractures and pores) all contribute to shale instability.
Safe drilling requires customized mud tailored to each shale type.WBM2, with its optimal KCl concentration and polypeptide suppressant, is the most reliable.Study results confirm its positive slope and immediate interaction with shale.WBM1 leads to higher swelling for both formations: In Tanuma, 6.13% (WBM1) and 3% (WBM2), compared to 3.01% and 1.53% with the Zubair sheal Formation, respectively.These findings have practical implications for cost-saving drilling mud development, effectively addressing shale instability concerns.

Fig. 12 .
Fig. 12.The hot rolling results for Tanuma and Zubair shale units

Table 1 .
Contains the CST data for both Tanuma and Zubair shales

Table 1 .
For the Tanuma shale, a KCl