This paper aims to define the geological characteristics, lithofacies, and depositional setting of the sandstones in a Saudi Arabian formation based on an outcrop detailed study. The information gathered from the outcrop study is integrated with mechanical and geochemical parameters of sand grains. The sandstone succession of Saudi Arabia is exposed along the margins of the Arabian shield and extends from north to south. This succession exhibits sandstone, which was deposited mainly in continental-to-shallow marine environments (fluvial, glacial and pro-glacial, Aeolian, and shallow marine). Hence, it displays a wide range of lithofacies, including fine-grained, medium-grained, coarse-grained, pebbly, conglomeratic, bioturbated, and crossbedded massive sandstone facies. Representative samples from each facies were carefully acquired for laboratory studies of geomechanical and geochemical analysis.
A correlation of field and laboratory observations can help determine potential application of sands in the petroleum industry (e.g., fracturing and sand control operations). Geochemically and morphologically, these facies mainly consist of moderate-to-well-sorted and rounded-to-well-rounded silica-rich sandstone. There have been a number of studies performed on sands from Southeast Asia and North America; however, no such studies have been performed on the Middle East region sands, even though the region possesses significant sand reserves. Therefore, evaluation of the sand from the Saudi Arabian region is a significant step towards its use in various oilfield applications.
High-resolution geological properties in combination with geomechanical and geochemical properties of sandstone and sand can reveal their potential as fracturing sands. This study defines potential fracturing sand in Saudi Arabia based on geological characteristics, lithofacies, and depositional setting. This study can help operators and service companies design very cost-effective fracture jobs using sand from this region.
Drilling oil-producing lateral wells often requires the use of an efficient drill-in fluid (DIF). A properly designed reservoir DIF with precise control of its properties is essential to help prevent formation damage that can impede production. This paper discusses the custom use of a DIF to reduce damage while drilling a lateral well to help maximize productivity during later stages.
Oil-based mud (OBM) with density of approximately 67 lbf/ft3 was formulated based on reservoir data by optimizing the particle size distribution (PSD) of the bridging materials used to effectively bridge against the average pore throat sizes. It was tested in the laboratory at simulated reservoir conditions and applied in the field at the target well. The fluid was continuously monitored at the rig for PSD and fluid loss control using the particle plugging test (PPT). The hole cleaning and equivalent circulating density (ECD) were simulated with proprietary hydraulics software.
Using nondamaging specialty products that reduce fines and fluids invasion is an essential prerequisite for a reservoir DIF. This paper describes the case history of drilling a horizontal well in a sandstone formation in Saudi Arabia and also shows the successful use of a reservoir DIF on lateral wells. It presents an approach that helps minimize formation damage, mitigate differential sticking, and drill a hole without having any hole problems. Implementation of this optimized fluid in the field while using specially designed practices to maintain the quality of the DIF during drilling led to a higher level of production rates.
This paper concludes that close monitoring of mud properties, optimization of PSD design, and the use of nondamaging specialty products helps minimize fluid invasion and deliver maximized production.
Unconventional reservoir exploration in the Middle East region is expected to continue to grow. The national oil companies in the Middle East have a strategy for maximizing their oil exports as well as use of natural gas. This puts an emphasis on use of advanced technology to extend the lives of conventional reservoirs and undertaking more activities in “unconventional gas and oil”. Understanding unconventional resources such as shale and tight (sand and carbonate) reservoirs requires unique processes and technologies based on reservoir properties for optimum reservoir production and well life. The objective of this study is to provide the systematic work flow to characterize an unconventional reservoir formation. This paper discusses the detailed Laboratory tests used to determine the geochemical, rock mechanical and formation fluid properties for reservoir development. The geochemical properties like total organic carbon content (TOC) are used to evaluate potential candidate for hydrocarbon, mineralogy evaluation is used to determine the formation type and clay content and kerogen typing for reservoir maturity. Formation fluid sensitivity like acid solubility tests of the formation, capillary suction time testing and core flow tests are used to understand the interaction of various fluids with the formation in order to optimize well development. An additional parameter in unconventional reservoirs is to plan ahead on implementing the right stimulation “fracturing” technique which requires determining the geo-mechanical properties of the reservoir as well as fluid to be used for stimulation. Properties of each reservoir are unique and require a unique approach to design and conduct the optimum fracturing solution. In this paper we will highlight the design of stimulation fluids based on reservoir characteristics and formation water properties. This paper will provide a broad overview of the reservoir characteristics used to determine the best completion and stimulation approach in unconventional reservoirs.
In gas condensate reservoirs, deliverability starts to decrease when retrograde condensation occurs. As the bottom-hole pressure drops below the dew-point, gas condensate and water build-up impede flow of gas to the wellbore. In order to stop the reduction in productivity, many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. Previous simulation work suggests an "optimum wetting state?? to exist where maximum gas condensate well productivity is reached. This work has direct application in gas-condensate reservoirs, especially in identifying the most effective stimulation treatment which can be designed to provide the optimum wetting conditions in the near-wellbore region.
In this work, we aim to show the existence of such an optimum state of wettability that result in maximum gas mobility and in an increase of the relative permeability curves. We present an experimental study on Berea sandstone rocks treated with a fluorinated polymer and investigate the optimum fluorinated polymer concentration that would alter the wettability to intermediate gas-wet. Different experimental techniquesincluding flow tests and spontaneous imbibition are conducted to examine the effect of treatments on wettability. Interaction between rocks and the fluids is studied using a MicroCT scanner.
The studies in this area are important to improve the productivity of gas condensate reservoirs where liquid accumulates, decreasing production of the well. Efficiency in the extraction of natural gas is important for the economic and environmental considerations of the oil and gas industry. Wettability alteration is one of the newest stimulation methods proposed by researchers, and shows great potential for future field applications and further research studies.
Trapping of spent acid after acidizing job is a major problem in carbonate rocks. Spent acid needs to be fully mobilized and recovered in order to enhance gas production. Wettability of the rocks and capillary forces are the main reason behind fluid trapping in carbonate formations. These forces can be weakened by decreasing surface tension and increasing contact angle. Additives that are injected along with the acid can have an impact on changing the surface tension, contact angle and possibly the wettability of the rocks. Previously, separate studies were conducted on the effect of acid additives on contact angle and surface tension. However, there is still a need to investigate the overall impact of acid additives on these two parameters and wettability on the trapping of spent acid in the carbonate rocks.
In this paper, the full impact of two additives, formic acid and methanol, on trapping and wettability is investigated. Irreducible fluid saturation is compared before and after the exposure of rocks to spent acid. Formic acid decreased irreducible fluid saturation whereas methanol increased irreducible fluid saturation. Spontaneous water imbibition was conducted in each case to ensure that there is no permanent effect on rock wettability as a result of using these additives. It is very important to understand that the effect of various additives on wettability must be studied before any acid job, as their impact on wettability can consequently affect well productivity.
Fluid mobility in porous media is highly affected by the fluid distribution and fluid wettability condition inside the pore space. Fluid wetting the rock tends to have a lower mobility compared to the non-wetting fluid. In petroleum engineering applications, changes in the wetting characteristics of the rock-fluid system can have a significant effect on well productivity. One example is condensate blocking, where the liquid condensate accumulates in high saturation near the wellbore due to the strong liquid-wetting, resulting in reduced gas mobility. Previous studies have shown that altering the wettability towards a gas-wetting state can enhance liquid mobility and reduce the accumulation in the near-wellbore region. Changes in the rock Wettability are usually studied either through contact angle measurements at the core scale, or through studies on the changes in fluid mobility characteristics. However, some researchers have been skeptical as to whether a state of gas-wetting can be achieved at the pore scale. In this work, we conducted an experimental study where we altered carbonate rock wettability from liquid-wetting to gas-wetting. This was achieved using a fluorinated polymer treatment. A new experimental setup was used combining a high resolution computed micro-tomography (MCT), to acquire 3D images of the rock-fluid system at pore scale. Pore spaces in the order of 50 to 200 micrometer were scanned at a resolution of 2 micron in order to visualize the liquid-air interface. It is evident from our work that achieving a state of gas-wetting at the pore scale is possible. 3D visualization is a very important tool to help us quantify the success of the polymer treatment and the uniformity of the surface coating. In order to conduct a similar study at higher temperature and pressure conditions, a visual cell is under design and will be discussed in future work.
The problem of condensate blocking in low permeability gas-condensate reservoirs is greatly affected by the rock-fluid interactions and capillary trapping. Many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. In this work, we present a simulation study on the optimum wettability conditions for maximum gas-condensate well productivity enhancement. Most of the work in this area focuses on reversal of wetting conditions from liquid-wetting (contact angle of 0 degree) to gas-wetting (with contact angle around 150 degrees). On the experimental side, chemicals are tested in its ability to change wettability. On the simulation side, research shows that changing the wettability to gas-wetting in the near wellbore region results in better productivity than the original liquid-wetting state. Our work investigates various states of wettability ranging from liquid-wetting to gas-wetting and its effect on gas-condensate well productivity. We also study the effect of reservoir permeability, reservoir pressure and treatment radius on the well productivity enhancement by wettability alteration.
The problem of condensate blocking in gas-condensate reservoirs has been widely discussed in the literature. Many publications present cases where the gas production rate is severely reduced due to condensate accumulation around the wellbore (Afidick et al., 1994; Barnum et al., 1995; El-Banbi et al., 2000). Other publications present methods that can be used to alleviate this problem including solvent injection (Al-Anazi et al., 2005) and hydraulic fracturing (Sognesand, S., 1991; Baig et al., 2005). These methods usually have limited success as it provides only a temporary solution to the problem.
An alternative method based on wettability alteration was suggested by researchers at the Reservoir Engineering Research Institute about 10 years ago (Li and Firoozabadi, 2000; Tang and Firoozabadi, 2002; Tang and Firoozabadi, 2003; Fahes and Firoozabadi, 2007; Wu and Firoozabadi, 2010). This method is based on reducing the liquid-wetting of the rock surface to enhance liquid mobility and reduce the accumulation of liquid condensate. A few other research groups at universities and companies have also been investigating this method (Bang et al., 2010; Ahmadi et al., 2010; Al-Anazi et al., 2007; Zheng and Rao, 2010). Pilot tests were also conducted in recent years (Butler et al., 2009; Liu et al., 2008).
In a pilot test in 2008 led by a team at Stanford University, a highly pressured tight gas-condensate reservoir was stimulated using wettability alteration (Liu et al., 2008). The permeability was 0.083 md and the reservoir pressure was 9688 psi. A temporary enhancement in the gas production rate was achieved but it was not sustained. The authors believe that the low permeability of the reservoir could be one of the main reasons for the failure. In another field application in 2009, a team from Trueblood Resources Inc., The University of Texas at Austin and 3M Company conducted a chemical treatment for a gas-condensate reservoir (Bang et al., 2010). The average permeability was 20 md and the reservoir pressure was 2971 psi. The gas production rate increased by a factor of three compared to the rate before treatment.
In this study, we show that the permeability is not the main parameter that determines the success of the treatment. The design of the treatment to optimize the gas end-point relative permeability is the main factor that controls the success of the stimulation procedure.