Heavy, viscous oil deposits and tar have low °API gravities and occur as part of several oil formations. Unlike normal oil deposits, heavy oil and tar tend to contain more inorganic impurities and to be more sulfurous and aromatic. And as so, they tend to have different responses to acidizing fluids during matrix acidizing treatments. One fundamentally interesting phenomenon is the wormholing characteristics ofacidizing tar formation. This paper discusses the effect of acid and its wormholing characteristic on tar and on carbonate rock that was saturated with crudes that have varying °API gravities. Experiments included acid flooding of core plugs that were saturated with different °API gravities. The extreme case included flooding the acid through tarsaturated plugs. The wormholes were characterized by CT Scanning. Differential pressures, number and sizes of wormholes and breakthrough volumes were all measured for each experiment. The tests involved regular hydrochloric acid and emulsified acids. This study showed that regular and emulsified acids produced comparable wormhole penetration in tar. Tar formations were difficult to exhibit face dissolution even at extremely low injection rates. In general, it was noticed that penetration and, hence, benefit from emulsified acid is reduced when higher °API oil saturated the rock. The wormhole breakthrough volume in a rock saturated with intermediate oil was less than that of a rock saturated with condensate oil. Condensate might have allowed better diffusion of acid droplets to react with the rock. This work provided a fundamental investigation that can lead to development in producing these challenging prospects. In addition, these results are of special interest when long horizontal injectors or producers are placed within the tar zone of conventional oil reservoirs.

Summary Acidizing is a common practice that aims to recover the initial skin factor or even decrease it further. Acids tend to create conductive channels (wormholes) through carbonate formations that connect the reservoir to the wellbore and bypass the damaged zones. Optimum wormholes are formed when certain conditions are met, such as optimum acid concentration and optimum injection rate. To thoroughly grasp wormhole creation, several characterization techniques should be performed. Computed-tomography (CT) scan and differential-pressure data are two practices commonly used for characterization of wormholing in laboratories by use of core-plug samples. Differential-pressure data and CT scan can verify the occurrence of acid breakthrough and qualitatively suggest the size and path of a wormhole. Nuclear magnetic resonance (NMR) was introduced in earlier studies as a new characterization tool for wormholes. NMR can detect the changes in micro- and macropores that are caused by acid injection, and it can indicate changes in interconnectivity between different pore systems and detect the materialization of formation damage induced by injected acids. However, the NMR technique cannot detect the new porosity corresponding to the generated wormhole because of an inability to sustain saturation fluids inside the core-plug samples. In this study, the NMR measuring method is further improved by use of a customized polytetrafluoroethylene (PTFE) tube as a container for core-plug samples. Because PTFE material does not interfere with NMR readings, this improvement allows the core-plug samples to maintain full saturation, which enables the detection of the new wormhole porosity. As a result, NMR can indicate different characteristics of the generated porosity, including the size of the wormhole and the changes in diffusion coupling and the distribution of each pore size. This technique can elaborate new aspects of wormhole generation and characteristics in carbonate reservoirs, in addition to assessing the damage caused by the stimulation fluid.

Waterflooding in different reservoirs for pressure maintenance and recovering more oil is a well established practice in the oil industry. Many research studies have shown that the success of any waterflooding process is mainly dependent on both physicochemical (fluid-rock) and geochemical (fluid-fluid) interactions. These interactions have been extensively investigated during seawater injection into carbonate formations. However, the rock/seawater chemical interactions are completely different in sandstone than in carbonate formations, due to different rock mineralogy. Therefore, the main objective of this paper is to investigate both the potential physicochemical and geochemical formation damage mechanisms that might occur during injection of seawater into a central Arabia sandstone formation.Scaling potential due to seawater-produced brine chemical interactions was investigated at an average reservoir temperature of 186°F, based on the Pitzer theory of electrolytes. In addition to the prediction data, laboratory compatibility tests were conducted to investigate the scaling potential in different seawater/produced brine mixtures at reservoir temperature. Since this sandstone formation contained different clays, such as illite and smectite, the clay swelling and fines migration tendency was explored using coreflood setup and zeta potential technique.The saturation index (SI) of different scales, such as calcium carbonate and calcium sulfate, was found to be mainly dependent on a seawater/produced brine mixing ratio. Additionally, it was found that scaling did not occur in supersaturated mixtures of seawater, aquifer water and produced brine, which indicated that there is a critical SI for the scaling onset. The zeta potential for different formation rocks was determined for sweater, aquifer and produced brine. It was nearly zero when using only seawater. One of the major findings of this study is that the presence of sulfate ions caused clay particles to migrate even in high total dissolved solid (TDS) seawater of nearly 55,000 ppm.

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Water production can reduce or block oil and gas production rates. In addition, the lifting, handling, and disposal of produced water negatively impact the hydrocarbon production economics. Among several techniques for water control, crosslinked polymer systems are the most effective for certain water shut-off projects. The objective of this paper is to assess the effectiveness of crosslinked polymer system for water control applications in carbonate formations and present its optimal formulation. This paper presents a detailed lab testing of a cross-linked polymer system. The system includes a gelling agent, primary and secondary crosslinkers and an acidic activator. The evaluation covered extreme concentrations of all components, temperatures up to 212°F, differential pressures up to 1,500 psi, actual field water salinity, wide range of permeability, and extended testing time up to three months. Core-flood experiments along with Computerized Tomography Scanning and Environmental Scanning Electron Microscopy were used to assess the sweep efficiency and the strength of the gel inside the core plugs. Losses of active ingredients from effluent samples were measured using Thermal Gravimetric Analyzer. Results of carbonate core plugs were compared with that of Berea sandstone. Strength of the gel at different cross-linker and polymer concentrations was monitored using sealed glass ampoules. Gelation times were measured using bottle tests and rotational viscometers. Extreme vertices design was used to optimize the experimental work and mixture triangle was used to represent the final results. An optimal gelling system with controlled gelation time and maximum performance was attained for the targeted formation at 212°F. It was found that the gelation time was affected by the three main components of the gelling system. The acetic acid-based activator was found to have the highest effect on the gelation time. However, this activator was not effective when the gelling system was tested in carbonate core plugs. A major effort of this work was to develop alternative strategies for the ineffectiveness of acidic activator in carbonaceous formations.