Microbial Alkalinity Production and Silicate Alteration in Methane Charged Marine Sediments: Implications for Porewater Chemistry and Diagenetic Carbonate Formation

A numerical reaction-transport model was developed to simulate the effects of microbial activity and mineral reactions on the composition of porewater in a 230-m-thick Pleistocene interval drilled in the Peru-Chile Trench (Ocean Drilling Program, Site 1230). This site has porewater profiles similar to those along many continental margins, where intense methanogenesis occurs and alkalinity surpasses 100 mmol/L. Simulations show that microbial sulphate reduction, anaerobic oxidation of methane, and ammonium release from organic matter degradation only account for parts of total alkalinity, and excess CO2 produced during methanogenesis leads to acidification of porewater. Additional alkalinity is produced by slow alteration of primary aluminosilicate minerals to kaolinite and SiO2. Overall, alkalinity production in the methanogenic zone is sufficient to prevent dissolution of carbonate minerals; indeed, it contributes to the formation of cemented carbonate layers at a supersaturation front near the sulphate-methane transition zone. Within the methanogenic zone, carbonate formation is largely inhibited by cation diffusion but occurs rapidly if cations are transported into the zone via fluid conduits, such as faults. The simulation presented here provides fundamental insight into the diagenetic effects of the deep biosphere and may also be applicable for the long-term prediction of the stability and safety of deep CO2 storage reservoirs.

Novel In-Situ Gelled Acid System Based on Inorganic Nanoparticles

Gelled acid systems based upon gelation of hydrochloric acid (HCl) are widely used in in both matrix acidizing and fracture acidizing treatments to prevent acidizing fluid leak-off into high permeable zones of a reservoir. The gelled up fluid system helps retard the acid reaction to allow deeper acid penetration for hydrocarbon productivity enhancement. The in-situ gelation is typically achieved by using crosslinked polymers with the acid. Conventional in-situ crosslinked gelled acid systems are made up of polyacrylamide gelling agent, iron based crosslinker and a breaker chemical in addition to other additives, with the acid as the base fluid. However, the polymer-based systems can lead to damaging the formation due to a variety of reasons including unbroken polymer residue. Additionally, the iron-based crosslinker systems can lead to scaling, precipitation and or sludge formation after the acid reacts with the formation, resulting in formation damage and lowering of hydrocarbon productivity. In this paper we showcase a new nanoparticles based gelled acid system that overcomes the inherent challenges faced by conventional in-situ crosslinked gelled acid systems. The new system can work in 5 to 20 % HCl up to 300°F. The new system does not contain any polymer or iron based crosslinker that can potentially damage the formation. It comprises nanoparticles, a gelation activator, acidizing treatment additives along with HCl. The new in-situ gelled acid system has low viscosity at surface making it easy to pump. It gels up at elevated temperatures and pH of 1 to 4, which helps with diverting the tail end acid to tighter or damaged zones of the formation. We demonstrate that the viscosification and eventual gelation of the new system can be achieved as the acid reacts with a carbonate formation and the pH rises above 1. As the acid further reacts and continues to spend there by increasing the pH beyond 4, the gel demonstrates reduction of viscosity. This assists in a better cleanup post the acidizing treatment. Various experimental techniques were used to showcase the development of the nanoparticle based acid diversion fluid. Static and dynamic gelation studies as a function of time, temperature and pH are reported. The gelation performance of the new system was evaluated at temperatures up to 300°F and discussed in the paper. Comparative performance of different types of gelation activators on the gelation profile of the nanoparticles is evaluated. It is also shown that the gelation and viscosity reduction is entirely a pH dependent phenomenon and does not require any additional breaker chemistry, and therefore provides more control over the system performance. The novelty of the new gelled acid system is that it is based upon nanoparticles making it less prone to formation damage as compared to a crosslinked polymer based system.

Therapeutic Role of Element Anhydrase Inhibitors in Treatment of Glaucoma: A Review

Eye disease may be a cluster of inveterately progressive disorders of the nervus opticus. during this article, I gift the medicine, Pathophysiology, risk factors, ophthalmic examination, and therapeutic role of carbonaceous anhydrase inhibitors in treating eye disease. In European countries, the prevalence of eye disease is a pair of.93% among persons aged 40-80 years, reaching ten you tired of persons over ninety years old-time. There is a unit many differing types of eye disease, and that they are classically divided into classes of open-angle and closed-angle eye disease. Use of topical selective or nonselective beta-blockers is used in the treatment of eye diseases. Second-line drugs of alternative embody alpha – agonists and topical carbonaceous anhydrase inhibitors. Parasympathomimetics drugs, most ordinarily alkaloid, area unit thought-about third-line treatment. For patients, the United Nations agency doesn't reply to antiglaucoma remedy, optical laser incisional and trabeculoplasty surgery area unit more ways that may be accustomed lower the pressure. The inhibitors area unit used medication in the treatment of symptom coronary failure, brain disease, and hypoxia conjointly. A Corollary of Friedenwald's construct of hydrogen carbonate secretion within the formation of liquid body substance is that inhibition of the protein carbonaceous anhydrase could be expected to decrease the speed of secretion and lower IOP. The carbonaceous anhydrase matter, Diamox (acetazolamide) is employed in the treatment of eye disease. Preliminary trials of Diamox in rabbits created a definite lowering of pressure to once ten to one hundred mg. carbonaceous anhydrase inhibitors diminish ocular high blood pressure in glaucomatous patients by reducing the hydrogen carbonate formation.

Complex Stimulation Approach to Low-Temperature Carbonate Formation Revitalizes Bahrain Brownfield

Carbonate formations often require stimulation treatments to be developed economically. Sometimes, proppant fracturing yields better results than acid stimulation. Carbonates are seldom stimulated with large-mesh-size proppants due to admittance issues caused by fissures and high Young’s modulus and narrow fracture width. The Magwa formation of Bahrain’s Awali brownfield is a rare case in which large treatments using 12/20-mesh proppant were successful after the more than 50 years of field development. To achieve success, a complex approach was required during preparation and execution of the hydraulic fracturing campaign. During the first phase, the main challenges that restricted achieving full production potential in previous stimulation attempts (both acid and proppant fracturing) were identified. Fines migration and shale instability were addressed during advanced core testing. Tests for embedment were conducted, and a full suite of logs was obtained to improve geomechanical modeling. In addition, a target was set to maximize fracture propped length to address the need for maximum reservoir contact in the tight Magwa reservoir and to maximize fracture width and conductivity. Sufficient fracture width in the shallow oil formation was required to withstand embedment. Sufficient conductivity was required to clean out the fracture under low-temperature conditions (124°F) and to minimize drawdown along the fracture considering the relatively low energy of the formation (pore pressure less than 1,000 psi). Understanding the fracture dimensions was critical to optimize the design. Independent measurement using high-resolution temperature logging and advanced sonic anisotropy measurements after fracturing helped to quantify fracture height. As a result of the applied comprehensive workflow, 18 wells were successfully stimulated, including three horizontal wellbores with multistage fracturing - achieving effective fracture half-lengths of 450-to 500-ft. Oil production from the wells exceeded expectations and more than doubled the results of all the previous attempts. Production decline rates were also less pronounced due to achieved fracture length and the ability to produce more reservoir compartments. The increase in oil recovery is due to the more uniform drainage systems enabled by the conductive fractures. The application of new and advanced techniques taken from several disciplines enabled successful propped fracture stimulation of a fractured carbonate formation. Extensive laboratory research and independent geometry measurements yielded significant fracture optimization and resulted in a step-change in well productivity. The techniques and lessons learned will be of benefit to engineers dealing with shallow carbonate reservoirs around the world.

Utilizing NMR Workflow to Optimize Power Water Injector Placement in the Presence of Tar Barriers

The objective of this work is to optimize the placement of horizontal power water injector (PWI) wells in stratified heterogeneous carbonate reservoir with tar barriers. The key to successful reservoir navigation is a reliable real-time petrophysical analysis that resolves rock quality variations and differentiates tar barriers from lighter hydrocarbon intervals. An integrated workflow has been generated based on logging-while drilling (LWD) triple combo and Nuclear Magnetic Resonance (NMR) logging data for fluid identification, tar characterization and permeability prediction. The workflow has three steps; it starts with the determination of total porosity using density and neutron logs, the calculation of water-filled porosity from resistivity measurements and an additional partitioning of porosity into bound and free fluid volumes using the NMR data. Second, the total and water-filled porosity, the NMR bound fluid and NMR total porosity are used as inputs in a hydrocarbon compositional and viscosity analysis of hydrocarbon-bearing zones for the recognition of tar-bearing and lighter hydrocarbon intervals. Third, in the lighter hydrocarbon intervals, NMR logs are further analyzed using a multi-cutoff spectral analysis to identify microporous and macroporous zones and to calculate the NMR mobility index. The ideal geosteering targets are highly macroporous rocks containing no heavy hydrocarbons. In horizontal wells, the method is validated using formation pressure while drilling (FPWD) measurements. The procedure has been utilized in several wells. The original well path of the first injector was planned to maintain a safe distance above an anticipated tar-bearing zone. Utilizing the new real-time viscosity evaluation, the well was steered closer to the tar zone several feet below the original plan, setting an improved well placement protocol for subsequent injectors. In the water- or lighter hydrocarbon-bearing zones, spectral analysis of NMR logs clearly accentuated micro- and macroporous carbonate intervals. The correlation between pore size and rock quality has been corroborated by FPWD mobility measurements. In one well, an extremely slow NMR relaxation may indicate wettability alteration in a macroporous interval. An integrated real-time evaluation of porosity, fluid saturation, hydrocarbon viscosity and pore size has enhanced well placement in a heterogeneous carbonate formation where tar barriers are also present. The approach increased well performance and substantially improved reservoir understanding.

A Non-Damaging Gelled Acid System Based on Surface Modified Nanoparticles

Gelled acid systems based upon gelation of hydrochloric acid (HCl) are used widely in acid stimulation treatments to prevent fluid leak-off into the high permeable zones of a reservoir. The gelled-up fluid system helps retard the acid reaction to allow deeper acid penetration for hydrocarbon productivity enhancement. Conventional in-situ crosslinked gelled acid systems are made up of polyacrylamide gelling agent, iron-based crosslinker, and a breaker chemical in addition to other additives, with the acid as the base fluid. The polymer-based systems can lead to damage to formation due to a variety of reasons including unbroken polymer residue. Additionally, the iron-based crosslinker systems can lead to scaling or precipitation after the acid reacts with the formation, resulting in formation damage and lowering of hydrocarbon productivity. In this paper, we showcase a new nanoparticles-based gelled acid system that does not contain any polymer or iron-based crosslinker that can potentially damage the formation. It comprises nanoparticles, a gelation activator, acidizing treatment additives along with HCl. The new in-situ gelled acid system has low viscosity at surface making it easy to pump. With increase in the temperature and as the acid spends there is a viscosity increase. The viscosification and eventual gelation of the new system can be achieved as the acid reacts with a carbonate formation. As the acid further reacts and continues to spend, the gel demonstrates reduction of viscosity. This assists in a better cleanup post the acidizing treatment. Various experimental techniques were used to highlight the development of the nanoparticle-based acid diversion fluid. The gelation properties of the acid system, as a function of acid strength and temperature, are investigated. Static and dynamic gelation studies as a function of time, temperature and pH are reported. It is demonstrated that the viscosification property is a function of pH and the gelation occurs in a pH widow from 1 to 5 pH units. The gelation performance of the new system is evaluated at temperatures up to 300°F. The effect of different types of surface modification chemistries on the gelation properties is investigated. It is also shown that the gelation and viscosity reduction is entirely a pH dependent phenomenon and does not require any additional breaker chemistry; and therefore provides more control over the system performance. The new gelled acid system overcomes the inherent challenges faced by conventional in-situ crosslinked gelled acid systems; as it is based upon nanoparticles making it less prone to formation damage as compared to a crosslinked polymer-based system.

Prediction of Hydraulic Flow in the New Zohr Carbonate Reservoir, Eastern Mediterranean Using Artificial Neural Networks

A new gas reservoir includes the carbonates of upper-Cretaceous Formation in the Zohr oilfield of eastern Mediterranean Sea in Egypt. The main aim of this study is to assess the new carbonate reservoir by thin section study and estimate hydraulic flow units HFUs by smart system. This carbonate formation is now considered the most important gas reservoir in northern Egypt. In this paper five microfacies were identified based on microscope petrographic analysis. The examined rocks were formed in lagoon, shoal and open marine depositional environments. The relationships between microfacies and flow units are further evaluated in this study. The determination of such relationships have proven to be challenging due to petrographic complications arising from diagenetic processes. The correlation behind pore space percentage and permeability is important to recognize hydraulic flow in the reservoir under consideration in this study.

Application of Wellbore Strengthening Techniques in Carbonate Formation Solves Lost Circulation Challenges During Liner Running and Cementing

For many years, the oil and gas industry has deployed techniques which enhance formation strength via the successful propping and plugging of induced fractures. Induced fracture sizes have been successfully treated using this method up to the 600 – 1,100-micron range. Static wellbore strengthening techniques are commonly deployed to cover 1,000 micron and all fracture size risks underneath. The deployment of wellbore strengthening techniques has historically been confined to permeable formations. In most cases, wellbore strengthening has been deployed to operationally challenging sand fracture gradients or, where boundaries are pushed, lower ranges of permeability, such as silts. The subject of wellbore strengthening in shales or carbonates to this day, remains a challenge for the industry, with very few documented success stories or evidence of sustained ability to enhance fracture gradient across a drilling campaign. This paper covers the history of lost circulation events which have been reported in the Khazzan/Ghazeer field in the carbonate Habshan formation. It also describes the design changes which were introduced to strengthen the rock and enable circulation/returns, during liner cementation. The design work built on experience applying wellbore strengthening techniques in carbonates in the Norwegian sector of the North Sea. This work is also summarized in this paper. The Habshan carbonate formation in Oman presents a lost circulation challenge through an ‘induced’ fracture risk. Since the beginning of the drilling campaign in the Khazzan/Ghazeer field, the Habshan formation has repeatedly experienced induced mud losses during well activities such as liner running, mud conditioning with liner on bottom and cementing, when the formation is exposed to higher pressures, less so during drilling. The Habshan challenge in Oman has led to regular, significant lost circulation events during cement placement, adding operational cost and more importantly, presenting difficulties around meeting zonal isolation objectives. Through previous field experience in Norway, a set of criteria was developed to qualify a standard pill approach to carbonate strengthening. The currently deployed strategy is designed to address both the risk of induced fracture by propping and plugging (wellbore strengthening) and provide some ability to seal natural fractures which are often encountered with carbonates, or similarly flawed rocks. The strategy deployed aims to cover these two risks with a blanket approach to lost circulation risk in carbonates. The success of this approach is demonstrated using well performance data from a total of 43 wells drilled before and after the introduction of the wellbore strengthening strategy. As it was initially assumed that wellbore strengthening could not be applied to carbonate formations, other techniques had been tried to prevent lost circulation. Those techniques provided mixed results. Since the implementation of wellbore strengthening significant improvements in achieving zonal isolation requirements and reducing fluid losses have been documented.

Engineered Composite Lost Circulation Solution to Successfully Cure Total Losses During Drilling Across Naturally Fractured Formations in Ghawar Gas Field, Saudi Arabia

Lost circulation is one of the major challenges while drilling oil and gas wells across the world. It not only results in nonproductive time and additional costs, but also poses well control risk while drilling and can be detrimental to zonal isolation after the cementing operation. In Ghawar Gas field of Saudi Arabia, lost circulation across some naturally fractured formations is a key risk as it results in immediate drilling problems such as well control, formation pack-off and stuck pipe. In addition, it can lead to poor isolation of hydrocarbon-bearing zones that can result in sustained casing pressure over the life cycle of the well. A decision flowchart has been developed to combat losses across these natural fractures while drilling, but there is no single solution that has a high success rate in curing the losses and regaining returns. Multiple conventional lost circulation material pills, conventional cement plugs, diesel-oil-bentonite-cement slurries, gravel packs, and reactive pills have been tried on different wells, but the probability of curing the losses is quite low. The success with these methods has been sporadic and shown poor repeatability, so the need of an engineered approach to mitigate losses is imperative. An engineered composite lost-circulation solution was designed and pumped to regain the returns successfully after total losses across two different formations on a gas well in Ghawar field. Multiple types of lost-circulation material were tried on this well; however, all was lost to the naturally fractured carbonate formation. Therefore, a lost-circulation solution was proposed that included a fiber-based lost-circulation control (FBLC) pill, composed of a viscosifier, optimized solid package and engineered fiber system, followed by a thixotropic cement slurry. The approach was to pump these fluids in a fluid train so the FBLC pill formed a barrier at the face of the formation while the thixotropic cement slurry formed a rapid gel and quickly set after the placement to minimize the risk of losing all the fluids to the formation. Once this solution was executed, it helped to regain fluid returns successfully across one of the naturally fractured zones. Later, total losses were encountered again across a deeper loss zone that were also cured using this novel approach. The implementation of this lost-circulation system on two occasions in different formations has proven its applicability in different conditions and can be developed into a standard engineered approach for curing losses. It has greatly helped to build confidence with the client, as it contributed towards minimizing non-productive time, mitigated the risk of well control, and assisted in avoiding any remedial cementing operations that may have developed due to poor zonal isolation across certain critical flow zones.