As the demand of energy is increased the oil and gas industry is continuously trying to develop innovative technologies which will be used to increase the production of oil and gas in future. Besides many enhanced oil recovery techniques are present, the sandstone acidizing has been significantly developed to contribute to the petroleum industry. In sandstone acidizing different acids and their combination are applied on the formation. This results in minimizing the near wellbore damage and improve the well productivity. In this project we have performed acidizing on the sandstone rock of Ranikot formation which is present in the Lower Indus Basin. Drilling machine with different drill bit sizes are used to obtain different core samples from the formation rock. We applied HCl and HF acid, and their combination on the sandstone rock. In this project we observed the sandstone acidizing mechanism with different acids and observed problems that occurs due to the application of different acids on the formation. The laboratory results shows that the acidizing perform well when we use the mud acid which is the combination of HCl and HF acid. In the case of HCl acidization, most of the sandstone rock samples completely dissolve in the acid recipe and lose the bulk volume. But in the case of HF acidizing the rock cannot dissolve in the solution but precipitation takes place.
TABLE OF CONTENTS
Chapter 1 Lower Indus Basin
1.1 Sedimentary Basin in Pakistan
1.2 Lower Indus basin:
1.2.1 Source rock of lower Indus basin:
1.2.3 Reservoir rock of lower Indus basin:
1.2.4 Ranikot Formation:
1.2.4 Formation and their depth present in lower Indus basin:
1.2.5 Discoveries in Lower Indus Basin:
1.2.6 Formation and discoveries in Lower Goru Formation of Lower Indus Basin:
Chapter 02 Porosity and Permeability
2.1 RESERVOIR ROCK PROPERTIES
2.1.1 Permeability
2.2 PERMEABILITY DETERMINATION
2.2.1 Procedure
Chapter 3 Matrix Acidizing
3.1 Abstract:
3.2 Well Stimulation:
3.3 Minerals in Sandstone:
3.4 Sandstone acidizing:
3.4.1 Acidizing Mechanism
3.4.2 Precipitates formation during Acidization in Sandstone
3.4.3 Solution to avoid Precipitation:
3.5 Problem associated with acidizing:
Chapter 4 Experimental Setup
4.1 Drilling and Coring
4.1.1 Definition:
4.1.2 Drilling Machine
4.1.2.2 Column:
4.1.2.4 Worktable:
4.1.2.5 Drill head:
4.1.2.6 Spindle:
4.1.2.7 Chuck:
4.1.2.8 Gears:
4.1.2.9 Electric Motor:
4.1.2.10 Drill Bits:
4.1.2.11 Procedure:
4.2 Porosity Calculations:
4.2.1 Procedure to determine the porosity of core sample using helium porosimeter
4.3 Permeability Calculations
4.3.2 Measuring Permeability by using Gas Permeameter:
4.4 Acid Recipe:
4.4.1 Acidizing Procedure:
Chapter 5 Results and Conclusions:
5.1 Drilling and Coring Process
5.1.1 Observation and Calculation:
5.1.2 Comments:
5.1.3 Precautions:
5.2 Porosity calculation before Acidizing
5.2.1 Observation and Calculation
5.3 Acid Recipes
5.3.1 Acid recipe using HCl
5.3.2 Acid recipe using HF
5.3.3 Acid recipe using HCl and HF
5.4 Porosity Calculations after Acidization
5.4.1 Observation and Calculation
5.4.2 Pictorial view of acidized core
5.6 Acid Recipes for small diameter samples
5.6.1 Acid recipe using HCL and pictorial representation of acidized cores
5.6.2 Acid recipe using HF and pictorial representation of acidized cores
5.6.3 Acid recipe using HCl and HF and pictorial representation of acidized cores
CHAPTER 6
Conclusion
DEDICATION
Dedicated to The Last Prophet Hazrat Muhammad (P.B.U.H) and His beloved daughter Hazrat Fatima Zahra (A.S) for Their blessings and benevolence. We would also like to dedicate this Final Year Project to our supportive families, and friends who stood by us in times of need.
ACKNOWLEGMENT
First and foremost, we want to express our gratitude to Almighty Allah for providing us with the strength to complete this task. It brings us great pleasure to convey our sincere thanks and respect to Sir Azam Khan, our supervisor, for instilling confidence and excitement in us and inspiring us in our work through his encouragement and advice.
Our sincere and deepest gratitude to her for his invaluable advice and suggestions. As his pupils, we present this dissertation work with great pride and joy.
Last but not least, we want to express our gratitude to our parents for their unwavering love, devotion, helpfulness, and support.
University of Engineering and Technology, Lahore, May 2022
List of figures
Figure 1: Lower Indus basin’s tropical view[2]
Figure 2:Ranikot Formation Outcrop
Figure 3:Generalized Stratigraphic column of Lower Indus Basin, Pakistan modified after Shah [6]
Figure 4: Creaming curve of the Lower Goru in Middle and Lower Indus Platform [8]
Figure 5: Core permeability vs. core porosity crossplot; data from an Asian gas field
Figure 6:: Crossplots of core permeability at stressed vs. surface conditions and core permeability ratio vs. core permeability at surface conditions
Figure 7: Drill Machine
Figure 8: 40 mm & 30 mm core bits
Figure 9: 40 mm & 30 mm core bits
Figure 10: Targeting the drill bit on the formation
Figure 11: Used drill bits 40mm
Figure 12: Used Drill bit 30mm
Figure 13: Drilling the formation
Figure 14: Hammer and Chisel Process
Figure 15: Grinder
Figure 16: Cutter
Figure 17: Irregular shaped core samples
Figure 18: Plained Samples
Figure 19: Plained samples
Figure 20: Gas Permeameter
Figure 21: Distilled water
Figure 22: Inserting sample
Figure 23: Resistivity measurement
Figure 24: Acidized Solutions
Figure 25: Tilted core sample due to lose drill bit in the drill chuck
Figure 26: Stratified breakage of core samples
Figure 27: Breaking due to fault during the core obtaining process
Figure 28: Deformed core during cutting and grinding
Figure 29: Core sample after acidization
Figure 30: Core sample after acidization
Figure 31: Core sample after acidization
Figure 32: Core sample after acidization
Figure 33: Core sample after acidization
Figure 34: Core sample after acidization
Figure 35: Core sample after acidization
Figure 36: Core sample after acidization
Figure 37: Core sample after acidization
Figure 38: Core sample after acidization
Figure 39: Core sample after acidization
Figure 40: Core sample after acidization
Figure 41: Core sample after acidization
Figure 42: Core sample after acidization
Figure 43: Core sample after acidization
Figure 44: Core sample after acidization
Figure 45: Core sample after acidization
Figure 46: Core sample after acidization
Figure 47: Before and After of Acidization
Figure 48: Before and After of Acidization
Figure 49: Before and After of Acidization
Figure 50: Before and After of Acidization
Figure 51: Before and After of Acidization
Figure 52: Before and After of Acidization
Figure 53: Before and After of Acidization
Figure 54: Before and After of Acidization
Figure 55: Before and After of Acidization
Figure 56: Before and After of Acidization
Figure 57: Before and After of Acidization
Figure 58: Before and After of Acidization
Figure 59: Before and After of Acidization
Figure 60: Before and After of Acidization
Figure 61: Before and After of Acidization
Figure 62: Before and After of Acidization
Figure 63: Before and After of Acidization
ABSTRACT
As the demand of energy is increased the oil and gas industry is continuously trying to develop innovative technologies which will be used to increase the production of oil and gas in future. Besides many enhanced oil recovery techniques are present, the sandstone acidizing has been significantly developed to contribute to the petroleum industry. In sandstone acidizing different acids and their combination are applied on the formation. This results in minimizing the near wellbore damage and improve the well productivity. In this project we have performed acidizing on the sandstone rock of Ranikot formation which is present in the Lower Indus Basin. Drilling machine with different drill bit sizes are used to obtain different core samples from the formation rock. We applied HCl and HF acid, and their combination on the sandstone rock. In this project we observed the sandstone acidizing mechanism with different acids and observed problems that occurs due to the application of different acids on the formation. The laboratory results shows that the acidizing perform well when we use the mud acid which is the combination of HCl and HF acid. In the case of HCl acidization, most of the sandstone rock samples completely dissolve in the acid recipe and lose the bulk volume. But in the case of HF acidizing the rock cannot dissolve in the solution but precipitation takes place. As a result, there is minor increase in porosity and permeability. If we applied mud acid on the formation, fractures and channels creates in the formation and there is a significant increase in the rock porosity and permeability.
Chapter 1
Lower Indus Basin
1.1 Sedimentary Basin in Pakistan
Pakistan has a total sedimentary basin area of roughly 827,000 km2, although only about 10-20% of it has been explored. The region is further classified into three sedimentary sub-basins: the Pishin Basin, the Indus Basin, and the Baluchistan Basin. The Indus sedimentary basin is largest basin and is further divided in to three sub-basins, the upper Indus basin, central Indus basin, and lower Indus basins. The Upper and Central Indus Basins are located mostly in the KPK and Punjab Province, Pakistan, while the Lower Indus basin is located in Sindh Province of Pakistan. The Lower Indus basin runs from 24° to 28° N and 66° E, about to Pakistan's southern border. It's a north-south oriented basin having a thick tertiary series underlain by earlier sequences and Quaternary deposits overlain. It spans approximately 250 kilometers and remained mostly constant throughout the Mesozoic epoch.
Tectonic division of Lower Indus basin includes the Kirthar Foredeep belt, Kirthar Fold Belt, Zone of Upward, Plateform Slope and region of Down warp. The structural highs of the basin resemble a finger extending from the Indo-Pakistan Shield. The estimated resources of each basin in Pakistan is given in Table 1.
Table 1: Estimated Resources of each sedimentary basin in Pakistan (Ahmed, 1998; Raza 1990 & Ahmed, 1990) [1]
Abbildung in dieser Leseprobe nicht enthalten
1.2 Lower Indus basin:
In the Sindh province of Pakistan, the Lower Indus Basin is a tectonostratigraphic-graphic province that lies between latitudes 231–351N and 281–301N, and longitudes 661–421E and 711–11E. The Thar Platform is predominantly an oil and gas producing region, and it is assumed to be the continuation of India's oil-producing Cambay and Cutch Rift basins, which arose in the early Cretaceous as a result of the Indian Plate's south western border divergence. As a result of extension altectonics, slanted fault blocks formed, trapping hydrocarbons created during the Cretaceous. The northwest migration of the Indian Plate created compression, and the counter-clockwise rotation caused tension. As a result of the stress, the Platform was separated into grabens and horst, resulting in excellent structures for oil accumulation/reservoirs.
Extensional tectonics determines the presence of oilfields in the Monocline's central part, as well as condensate fields and gas fields are found in the south-western and north-eastern blocks of basin. The most important unit in the Lower Indus Basin in terms of petroleum reservoirs is the Goru formation. While the Goru formation is divided into lower and higher portions based on its lithological components. The formation's upper layer is mostly shale with a small amount of sand, with a tendency to travel down to the bottom section, where it has evolved into a potential reservoir in the Lower Indus Basin. Lower Goru sands have exceptional reservoir properties, with high porosity ranging from 5% to 40% and permeability exceeding 1 Darcy in many locations. Because of the prevalence of pelagic species, the habitat appears to have been maritime. Because of presence of all of the hydrocarbons found in the monocline of Sindh in the Lower Goru sand, the Lower Goru sand has excellent petroleum potential.
The hydrocarbons present in the Lower Indus sedimentary basin range from light to heavy condensates, according to earlier investigations. Waxy and highly paraffinic crude oils obtained have low Sulphur levels and high API gravities. Oils from various places, such as Golarchi, Dhabi, Khaskheli, Umer and Mazari have a significant content of wax, which can be seen in their chemistry. In the current study, organic geochemical parameters based on biomarker distributions of saturated HC fractions were used to investigate the source of OM, depositional environment, lithology, and thermal maturity of OM from the crude oil reservoir in the Cretaceous Formations Lower Indus Basin, Pakistan. Identification of the source and provenance of crude oils is crucial for oil exploration in the basin.
Abbildung in dieser Leseprobe nicht enthalten
Figure 1: Lower Indus basin’s tropical view[2]
Description:
Blue line: Kirthar fold belt region having conventional gas
Dark blue line: Kirthar foredeep region having conventional gas and oil
Grey line: Lower Goru-Sember Shale Oil
Orange line: Jacobadbad Mari conventional gas region
Yellow line: Jurassic Shale Gas region
Sky Blue line: Lower Goru Sember Shale Gas
1.2.1 Source rock of lower Indus basin:
The Cretaceous Sembar Formation is the principal source rock in the Lower Indus Basin. It is distributed throughout the Indus Basin. The Triassic Wulgai Formation also have the potential for source, with excellent to high detail, based on total organic carbon content. The depositional environment of the Triassic Wulgai Formation is on the outer shelf. The Goru Formation is important to Pakistan's hydrocarbon industry since it serves as a source, reservoir, and seal rock, among other things.
The Goru Formation is divided into two parts:
- Upper Goru
- Lower Goru.
The Upper Goru is a seal rock, whereas Lower Goru is a good hydrocarbon reservoir and act as a source rock some says it moderate source rock. A significant number of unconventional resources are found in the Talhar formation of Lower Goru. Source potential also exists in the Mughalkot, Ranikot, and Laki formations.
Table 2:Source rocks, their age, Formation, Depositional Environment present in Southern Lower Indus Basin [3]
Abbildung in dieser Leseprobe nicht enthalten
1.2.3 Reservoir rock of lower Indus basin:
The Lower Goru is a good to exceptional reservoir made up primarily of sandstone and mudstone. In the research area, the Chiltan Formation, which dates from the Jurassic period, serves as a fractured reservoir. The sand facies dominate in the basin's southern portion. According to porosity and permeability statistics, the Lower Goru Formation has exceptional reservoir quality. Some formation like Ranikot formation and the Pab formation of Lower Indus basin are considered to be the best formation and considered as good reservoir. Although little prospective exploration of the Neogene Nari and Gaj formations has been done, the reservoir quality of these formations is outstanding.
1.2.4 Ranikot Formation:
The Ranikot Formation, which is found in Bahawalpur, the Indus basin, and particularly in the Punjab platform, has been analyzed. TOC and Rock-Eval pyrolysis measurements were used to analyze the Ranikot sandstone formation. The average depth of Ranikot Formation is 2082m. Sandstones were analyzed, and twenty well cutting samples from the Ranikot Formation were assessed. Sandstone dominates the formation, with shale interbeds. The TOC in the tested samples ranges from 0.76 to 3.1 weight percent. The Rock-Eval S2 readings suggest low potential, with values ranging from 0.46 to 1.05 mg HC/g rock. The hydrogen index of the samples is modest, ranging from 21 to 113 mg HC/g TOC. Kerogen is mostly Type III organic materials from the ground. Tmax values for the tested samples range from 413 to 509 degrees Celsius. The upper half of the formation, from 490 to 560 meters deep, has a good to excellent TOC concentration and is in the transition zone between immature and mature zones. The total rock unit's genetic potential is low approximately less than 2.0 mg HC/g rock. The formation has limited potential, according to the analysis done on the analyzed samples. [4]
Abbildung in dieser Leseprobe nicht enthalten
Figure 2:Ranikot Formation Outcrop
1.2.4 Formation and their depth present in lower Indus basin:
As a developing country, Pakistan has major energy challenges as a result of a hydrocarbon shortage. To meet energy demands, it is therefore vital to accelerate the exploration and development of new oil and gas resources. Administratively, the research region is in Sindh Province, Pakistan's Southern Lower Indus Basin, and petroleum concession zone III.
According to a statistical technique that uses dispersion and central tendency on data from reservoir formation, the average depth of Chiltan Formation is 3578m in which 38 wells were drilled, accounting for 4% of the total wells. The Ranikot Formation, has an average depth of 2082m and only 18 wells contributing, is not well developed in the research zone. The average depths of Sember formation, Pab formation and Lower Goru formation are 3542m, 2359m, and 2254m, respectively, and contribute 737 wells to the total number of wells drilled in the research zone, and considered well developed in the research zone. The average depth of Eocene formations Sui Main Limestone (SML) is 1496m and the average depth of Habib Rahi Limestone is 812m, respectively, in both formation total 158 wells have been drilled, accounting for 15% of all wells drilled. Because of their low well density relative to worldwide norms, exploration and production (E&P) companies should concentrate on the L.G, SML, and HRL formations, according to the study. [4]
Table 3:Average depth of different formations in Lower Indus Basin [5]
Abbildung in dieser Leseprobe nicht enthalten
1.2.5 Discoveries in Lower Indus Basin:
The most studied sedimentary basin of Pakistan is the Lower Indus Basin. To the north, the Central Indus basin, to the northwest, the Sulaiman and Kirthar basins, and to the south west, the Central Indus basin. The rifting of the Indian plate is one of the major factors that influenced the architecture and sedimentology of the Lower Indus basin. In terms of petroleum exploration and success, it is the most successful basin. The basin has a total of 201 wells, with 35 oil wells and 37 gas wells yielding a very high success rate of up to 36%, setting it apart from all other basins in the area. The lower Indus platform basin is underlain by pre-Cambrian to modern clastics and carbonates. This basin contains six proved and prospective plays, each with its own complete petroleum system. In this section, the early Cretaceous rocks are considered likely source rocks for hydrocarbon production. The best reservoir rocks are carbonates and clastic rocks from the Cretaceous through the Eocene periods. Seal rocks include Cretaceous intra-formational shales. A diversity of structural occurrences characterizes the Indus Basin, providing a unique trapping mechanism. The Lower Indus Basin has emerged as the most potential basin for petroleum accumulation because to its unique blend of source, reservoir, seal, and trapping processes.
1.2.6 Formation and discoveries in Lower Goru Formation of Lower Indus Basin:
From the Lower Indus Platform areas of south-central Pakistan and south Pakistan, the Early-Late Cretaceous Lower Goru sands have developed as substantial hydrocarbon producers. However, due to a lack of understanding of reservoir distribution, much potential remains untapped. The exploration of structural and stratigraphic properties is facing a considerably lower success rate than that of conventional structural traps.
The use of sequence stratigraphy and the Lower Goru play's creaming curve as prediction tools can aid in the discovery of new exploration targets, the reduction of geological uncertainties (risks), and the advancement of exploration in the Lower Goru play. Rather than the "cream of the crop" being discovered early in a play's exploration history, i.e., a steep increase in cumulative discovered reserves followed by a terrace, the Lower Goru findings (Figure 3) suggest to more than one sharp limb on the creaming curve.
Instead of a simple creaming pattern of rising limb followed by a plateau phase, the lateral and vertical position of the producing Lower Goru reservoirs within a sequence stratigraphic framework can explain a more complex curve (Figure 3). Oil, condensate, and gas were discovered in the "C" and "D" sequences (Upper and Mi of the Lower Goru) by UTPI (now BPP) and then OGDCL in the Badin area between 1981 and 1985. The Lower Goru play's possibilities were first based on a structural play idea in horst blocks, and these finds showed an increasing trend before plateauing in the late 1980s.
In the 1990s, additional fields were identified on the down-thrown side of fault blocks, where stratigraphy controls the reservoir extent and geometry. Shorelines, Forced-regressive detached, shelf edge deltas, shoreface barrier bars, and laterally restricted deltaic distributary channels and lobes are all connected with reservoir sands.
Abbildung in dieser Leseprobe nicht enthalten
Figure 3:Generalized Stratigraphic column of Lower Indus Basin, Pakistan modified after Shah [6]
The discovery of disconnected shoreface sands in a basinward position beneath the structures contributed yet another large rising limb to the Lower Goru cumulative found IGIP and reserves. The creaming curve's youngest part has a rising form, owing to new oil, condensate, and gas discoveries in the Sinjoro and Mirpur Khas blocks. This creaming curve trend indicates that the Lower Goru lowstand detached sand play has not yet reached maturity, and that there are still many more discoveries to be made in the Lower and Middle Indus platform area, particularly in the form of upside from current D&P leases. [7]
Abbildung in dieser Leseprobe nicht enthalten
Figure 4: Creaming curve of the Lower Goru in Middle and Lower Indus Platform [8]
Chapter 02
Porosity and Permeability
The most important real qualities of reservoir rock are porosity and permeability. Porosity is a key distinguishing feature of reservoir rocks. Nonetheless, permeability is the most important attribute of a successful reservoir rock for explorationists. Both are mathematical features that arise as a result of its lithological, underlying, and compositional behavior. The real structures of a stone and its textural features, such as the sizes and states of the stone grains, their plan framework, and bundling, are mathematical. The productivity of reservoir rock is dependent on a variety of important qualities, however in this study, we will focus on porosity and permeability as the key themes.
2.1 RESERVOIR ROCK PROPERTIES
The reservoir porosity indicates how porous a reservoir rock is. It is also defined as;
“a percentage of the reservoir rock to store or contain liquids”
There are required and optional porosity, which are hereditarily organized based on typical sedimentologic depictions of reservoir rock.
(a) The following are the essential porosity types:
I) Intermolecular interactions
This type of compaction and cementation resulted in the instantaneous loss of rock content in muds and carbonate sands. This kind is mostly found in the form of siliciclastic sands.
ii) Intramolecular porosity, which is made up of the insides of carbonate skeletal grains.
Optional porosity is defined as the porosity framed after the affidavit prompts other reservoir types.
I) Dissolution porosity is formed by the disintegration and drainage of carbonate. Carbonate reservoirs are another name for it.
ii) Fracture porosity, which is characterized by a lack of volume. Rock morphology can also be used to order porosity. Pore spaces can have three different morphologies:
a) Catenary, in which the pore opens to several neck entries;
b) Cul-de-sac, in which the pore opens to only one throat entry; and
c) Closed, in which there is no association with other pores.
2.1.1 Permeability
The measure of a liquid's ability to pass through a porous medium of reservoir rock is called permeability. Permeability is one of the most important factors in determining a compelling reservoir. The parameters of porosity and permeability depict the reservoir rock limit in terms of liquid moderation. A reservoir rock might also be porous without being permeable. For explorationists, the determination of permeability of reservoir rock is a vital achievement because it is critical for determining whether it has sufficient business amassing oil, but estimating it is exceedingly difficult.
The estimation of permeability can be viewed in two independent ways. When the porous media is fully immersed in a single liquid, the permeability is displayed as complete or absolute permeability. When the porous medium is immersed in more than one liquid, the permeability is depicted as successful or relative permeability. The volume of reservoir rocks is influenced by a variety of factors. The permeability of a reservoir rock depends on the size, the state of grains, compaction and the arrangement of grains.
The state of the grains: grains with high sphericity will generally pack well to form a base pore space, a fact that increases rakishness and therefore pore space volume.
The arrangement or consistency of grain size has an impact on reservoir properties; the more uniform the grains are calculated, the greater the genuine volume of empty spaces. As a result, mixing grains of diverse sizes reduces the absolute volume of vacant space. If the grains are more compacted, the smaller the number of vacant spaces becomes. Sand compaction, on the other hand, is less effective than mud compaction. [10]
2.2 PERMEABILITY DETERMINATION
Making calculations on center samples and deciding permeability utilizing the procedures given in API RP 40 is the "gold" standard for permeability.
Back to center estimations are applied to all processes. However, because center estimations only test a small portion of the reservoir, we should rely on methodologies that can be used in a broad design across the reservoir. Sidewall tests, relationships to wireline logging reactions, translation of atomic attractive reverberation (NMR) logs, wireline arrangement analyzer pressure reactions, and drill stem tests are all used in these approaches.
On field the permeability of rock reservoir is can be determined by using following techniques:
- Sidewall samples
- Correlations of wireline logging
- NMR Logs
- Wireline formation testers
- Drill Steam test
2.2.1 Procedure
A few reasons necessitate point-by-point permeability values at the wellbores across the reservoir interval. Engineers, for starters, demand circulation and a wide range of permeabilities in order to promote fruition procedures. Second, this equivalent data is required as part of the geocellular model and dynamic-flow calculations (e.g., numerical reservoir-reenactment models). The extent of shales and other low-permeability layers that block or baffle vertical flow is the primary consideration in each of these cases. The concept of permeability diversity is a subsequent consideration. Whether the high-permeability rock intervals occur in distinct layers from the low-permeability rock intervals, or whether there is enough variability that the high- and low-permeability intervals are personally interbedded.
Empirical equations can be used to estimate permeability when good-quality core data is unavailable. Pore size and pore-throat geometry, as well as porosity, all influence permeability. The widely used Timur equation [2] connects permeability to irreducible Sw and porosity, and so can only be employed in hydrocarbon-bearing zones to account for part of these characteristics. For a medium-gravity oil zone, this version of his equation applies: [11]
Abbildung in dieser Leseprobe nicht enthalten (2.1)
Where,
k = absolute permeability in millidarcies,
ϕe = effective (not total) porosity as a bulk volume fraction,
Sw = effective water saturation above the transition zone as a fraction of PV
The standard center investigation information is the starting point for permeability computations in field assessment. This data, as well as related SCAL estimates of permeability and porosity as a component of overburden pressure, are useful in determining permeability values at reservoir conditions and the permeability vs porosity relationship. The connection between permeability and porosity is typically assumed to be semilogarithmic, although with a more dramatic slant for low-porosity values. A and B show the characteristics of these links. From scheduling center examination data, Fig. A shows a consistent permeability against porosity relationship (the dissipate in these information increments at the lower-porosity levels). The permeability proportion (pushed permeability isolated by unstressed permeability) vs unstressed permeability is depicted in Fig. B. This proportion is a lot more modest for low-permeability values and approaches a worth of 1.0 for the high-permeability values.
Abbildung in dieser Leseprobe nicht enthalten
Figure 5: Core permeability vs. core porosity crossplot; data from an Asian gas field
Abbildung in dieser Leseprobe nicht enthalten
Figure 6:: Crossplots of core permeability at stressed vs. surface conditions and core permeability ratio vs. core permeability at surface conditions
The development of porosity and porousness in repository sandstone with deviatoric stress is investigated using traditional triaxial pressure tests and an in-situ pressure CT test. With the increase in limiting pressure, volumetric enlargement will be delayed. Because of the pressure of micro fractures and pores, porosity immediately decreases as deviatoric stress increases. After that, it will progress to the volumetric augmentation stage. Almost all pores in this high-porosity sandstone are linked, and trapped porosity is minimal. Another way to understand the porosity development with deviatoric stress is to examine the images in light of in situ pressure CT. Porosity variation with deviatoric stress is predictable with triaxial pressure testing, according to picture analysis, and the caught porosity is modest.
Low confining stress (0.2 MPa), which is close to uniaxial pressure conditions, was used to estimate porousness development. Because the starting micro fissures have closed, penetrability is extremely low at the underlying stacking level. The in-situ pressure CT test may clearly see the conclusion of micro cracks in the even heading. The decline in porousness during the volumetric enlargement stage is due to sand formation and convolution expansion. At high deviatoric stress, in situ pressure CT confirms that sand particles are broken and sand is delivered, and microcracks are incited inside sand particles in the vertical heading. Estimates based on pore network showing show a decrease in outright porousness with deviatoric stress.[13]
- The idea of linear poro elasticity for small loads led to the introduction of connections between compaction, porosity decrease, and pore-volume change.
- Three compaction zones in peff vs. Q stress space (where peff[(Sh+SH+Sv)/3]–pp and QSv–Sh) were discovered based on a literature survey of outcrop and reservoir sandstones, each with its own deformation processes and mesoscale deformation behaviour. Near-elastic, inelastic, and failure are the terms used to describe these domains.
- For some stress-path situations, the compaction-domain idea was applied to predict the extent of the near-elastic region in the SNOK sandstone reservoir. This corresponds to the "mechanically safe" depletion range, in which poroelasticity is believed to provide accurate predictions of rock mechanical behaviour.[14]
Chapter 3
Matrix Acidizing
3.1 Abstract:
The oil and gas sector are constantly working to create breakthrough oilfield technology in order to fulfil expanding global energy demands. Sandstone acidizing has made great progress in the petroleum sector as a result of the more development in enhanced and improved oil recovery processes. [15]
Matrix acidizing is a widely used sandstone stimulation process used to increase the pore volume to increase the permeability and porosity of the formation near a bottom-hole well. The acids like HF and HCL are mostly used for acidizing. Mud acid (HF–HCl) is the most commonly utilized acid. It's a combination of two inorganic acids, hydrofluoric acid and hydrochloric acids. However, the most common challenge with sandstone acidization by using mud acid is that mud acid does not perform well at high temperatures and has serious issues, like a very fast rate of reaction, which leads to early acid consumption. This disadvantage has a detrimental impact on sandstone acidizing since it causes permeability reduction and also acid treatment failure [16]. The formation has been treated with several acid combinations, which has to reduce the near-wellbore skin or damage and increase the productivity of well.
Matrix acidizing is a widely used well stimulation technique. Organic, inorganic acids and their combinations are fed into bottom-hole keeping pressure lower than the pressure of fracture formation during the process of acidizing. Sandstone matrix acidizing has been widely used and played an essential role in the oil and gas industry since the mid-1960s. After many years of hydrocarbon extraction from reservoir, various acids were devised to reactivate depleted sandstone reservoirs. Acid has a critical function in improving the permeability and porosity of formations. Acid also has another function: it reduces formation damage. [17]
3.2 Well Stimulation:
A technique used to boost the production of gas and oil from the formation or reservoir rock to the wellbore is known as well stimulation. Well stimulation is the process to increase the production from the well. Well stimulation do a crucial role in the development of oil and gas wells, to ensure the profitable outcome from these wells. More imaginative and new techniques to treating the wells have been used in recent years. The two most important well stimulation techniques are given as:
- Hydraulic Fracturing
- Matrix Acidizing
- Fracture Acidizing
Hydraulic fracturing boosts oil and gas output by injecting fluid at a pressure higher than the reservoir rock pressure into a reservoir well (Economides et al. 2013). In hydraulic fracturing the fluid is injected in to formation with pressure greater than the formation pressure for the purpose to create fractures and holes in the formation from where the hydrocarbon moves towards wellbore. Hydraulic fracturing continues to be the most popular well stimulation technique in the business.
While in acidizing, acids like HF, HCL and their combination has been applied on formations like carbonate and sandstone, to dissolve minerals like carbonate, feldspar and quartz present in reservoir rock, as a result the permeability and the porosity of the formation near the wellbore has been increased. As the permeability of the reservoir rock is increased due to acidizing the ultimate recovery of flow rate is increased from the wellbore.[18]
In the acidizing, the acid types used are organic acids, inorganic acids, the mixture of organic and inorganic acids, citric acid, sulfamic acid, chloroacetic acid, ethylene diamine tetracetic acid, benzoic acid, and erythorbic acid.[19]
Both hydraulic fracturing and matrix acidizing have their own limitation and advantages. The selection of hydraulic fracturing and the acidizing depends on many factors that includes:
-Formation geology
-Production history
-Well intervention objectives
The formation having high porosity and permeability does not need hydraulic fracturing in comparision with the tight formation. Due to the overburden pressure the loosely bounded formation can cause collapse of formation. Matrix fracturing using acids is mostly applicable to the carbonate formations that have high permeability and high rock fractures. Sandstone acidizing is also applicable to the depleted reservoirs of sandstone formation for the purpose of carbon capture storage, whereas implementation of hydraulic fracturing on the depleted sandstone reservoirs does not gives better results.[20]
3.3 Minerals in Sandstone:
Sandstone rock is a clastic sedimentary rock. At times sandstone is also known as arenite. It contains silica, SiO2, and a variety of silicate minerals. Quartz, feldspar and different forms of clay are considered to be the main composition of sandstone. Although uncommon, zeolite can also be found in sandstones.
Table 4: Mineralogy of a sandstone [21]
Abbildung in dieser Leseprobe nicht enthalten
3.4 Sandstone acidizing:
The primary goal of matrix acidization on sandstone is to remove or dissolve different particles present in sandstone specially the siliceous particles like clay, feldspar, and quartz because they obstruct hydrocarbon flow and diminish permeability near the wellbore. HF acid was widely used since 1935, on sandstone formations to repair formation damage and solve difficulties linked to production damage in sandstone and also solve difficulties linked to the drilling of sandstone. Initially, this acid's primary use was to clean the walls of pipes by removing the mud cake, now HF is used to solve a variety of issues, including the removal of particles mostly the siliceous particles and near wellbore damage. When treating sandstone formations with a tiny amount of calcium minerals, this acid proved to be quite effective. Because only the fluoride ion (F-) can react with silica and clay, the particles of sandstone formation like sand grains, feldspar, and clays show reaction with Hydrofluoric acid. Dowel came up with the notion of combining HCl and HF acids to prevent reaction products from precipitating in 1940. Smith and Hendrickson and Nasr-El-Din (1986) documented injecting mud acid (combination of HCl and HF acids) on the sandstone having a concentration of 12 percent HCl and 3 percent HF. Precipitation processes can occur as a result of fluid–mineral interactions, which can limit reservoir permeability. The reactions HCl and HF with carbonate, as well as the responses of HF with siliceous particles such as silicates particles, quartz particles, and feldspar particles, are the most critical concerns when the mud acid (combination of HCl and HF acids) show reaction with the formation for the purpose to remove or dissolve distinct minerals.
3.4.1 Acidizing Mechanism
As soon as HF acid penetrates a sandstone formation, it begins dissolving minerals. Mineral reaction and dissolution rates are determined by their acid reaction rate and exposed surface areas. Slow and quick reacting sandstone minerals are separated into two types. "Quartz tends to react more slowly, whereas feldspars and clays react more quickly." When mud acid is applied to a sandstone deposit, three types of reactions normally occur. [22]
Aluminum and silica fluorides are formed in the main reaction, which occurs near to the wellbore. Minerals are frequently dissolved quickly and without precipitation in these processes. It is said to be the primary reaction of acid in the formation.
The secondary reaction occurs when the aluminum and silica produced in primary reaction can react further to generate silica gel (slow reaction), a precipitate.
The Tertiary reaction occurs away from the wellbore or away from the injection zone, resulting in the formation of more silica gel.
The secondary and tertiary processes at high temperature may cause the sandstone acidizing treatment to fail. With formation rocks, the major reactant is HF acid, whereas hydrochloric acid (HCl) is purposely supplied to limit HF consumption and maintain an acidic environment.
Table 5: Solubility of Sandstone Mineral [23]
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[...]
- Quote paper
- Muhammad Awais (Author), 2022, A Laboratory Application of Acid Stimulation Technique in Sandstone Rock Samples from Lower Indus Basin, Munich, GRIN Verlag, https://www.grin.com/document/1282264
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