Purpose Although there is a boom in the construction industry in the Kingdom of Saudi Arabia (KSA), it is yet to fully adopt building information modeling (BIM), which has received a lot of attention in the US, UK and Australian construction industries. Thus, the purpose of this paper is to provide the current state of the art in BIM implementation in Saudi Arabia, as well as perceived benefits and barriers through a case study. Design/methodology/approach A broad overview of BIM, the construction industry in KSA and the research and implementation of BIM in KSA was presented in this study. The research further established the perceived benefits and barriers of BIM implementation through a case study of a local AEC firm. A questionnaire survey was used to obtain lessons learned from the BIM team of the pilot project and was further analyzed using the RII approach. Findings The study’s findings include the lack of policy initiatives in KSA to enforce BIM in the construction industry, as well as the lack of sufficient research in the domain of BIM in KSA. Furthermore, the case study also revealed that the most important benefit of BIM adoption is “detection of inter-disciplinary conflicts in the drawings to reduce error, maintain design intent, control quality and speed up communication,” whereas the most important barrier is “the need for re-engineering many construction projects for successful transition towards BIM.” Originality/value The study provides a background for enhanced research towards the implementation of BIM in Saudi Arabia and also demonstrates the potential benefits and barriers in BIM implementation.
A successful kill fluid formulation for the overpressured Jilh formation has been achieved. Jilh formation is a dolomitic middle Triassic tight zone that ranges from 8,000 to 10,000 ft TVD with abnormal salt-water pressure that requires a kill fluid with a density up to 150 lb/ft 3 (pcf). Addition of weighting materials such as barite (BaSO 4 ) or hematite (Fe 2 O 3 ) is needed to achieve the desired density for the kill fluid. However, maintaining high volume of solid content for barite particles (or any other weighting material) in suspension is challenging, especially for extended period of time. This phenomenon is described in the industry as static barite sag and it may lead to serious well control incidents and lost circulation.Saudi Aramco developed a new formula for kill fluids at high range of densities up to 150 pcf using barite with manganese tetroxide (Mn 3 O 4 ). No similar formulations were developed before to the best of the authors' knowledge. The properties of small particle size (D 50 ϭ1 m), spherical shape, and high specific gravity (4.95 g/cm 3 ) of manganese tetroxide make it a good weighting material to reduce solids loading and settling compared to barite (SGϭ 4.20 g/cm 3 and D 50 ϭ20 m). Results show that the density variation between the upper and lower section after 24 hours of vertical static condition is 5 pcf for the new formula (densityϭ 150 pcf) compared to a variation of 13 pcf for the conventional formula that has barite only. When the drilling fluid is put in inclined static condition for 24 hours, the density variation is 6 pcf for the new formula (densityϭ 150 pcf). However, the conventional formula showed a density variation of 17 pcf.The experimental work in this paper involved rheological properties, thermal stability, HT/HP filtration, and static sagging. This paper also describes field cases with barite sagging in high temperature wells and method and formulation of combining manganese tetroxide and barite to formulate new kill fluid formulations for Jilh Formation in Saudi Arabia fields.
Drilling Unayzah-B gas reservoir (shale and sandstone) in Saudi Arabia requires high mud density (± 95 pcf). To formulate this mud, calcium carbonate particles were used, because of their high acid solubility. However, when drilling the 5–7/8 inch hole, sticking occurred, which resulted in expensive fishing and/or sidetrack operations. To minimize these problems, barite was added with CaCO3 to reduce the amount of solids needed to formulate the drill-in fluid. However, barite is acid in-soluble and may cause formation damage. Formate drill-in fluids with low CaCO3 content were used to drill some wells in this reservoir, however these fluids are expensive and corrosive if their high pH values were not maintained in the field. Saudi Aramco has developed drill-in fluids that are based on manganese tetra oxide particles to drill deep gas reservoirs. The properties of these (D50 = 1 micron), spherical shape, and high specific gravity (4.8 g/cm3) make them good weighting material compared to CaCO3 (2.78 g/cm3 and D50 = 10 micron)and BaSO4 (4.25 g/cm3 and D50 = 20 micron). The main objective of this study is to discuss lab work that was performed to design water-based drill-in fluids using KCl/Mn3O4 at 95 pcf. A second objective is to compare the properties of the new fluid with two typical fluids that are currently used to drill Unayzah-B reservoir. The first fluid is KCl/BaSO4/CaCO3 and the second one is potassium formate/ CaCO3. The experimental work included measuring the rheological properties, thermal stability, API and HT/HP filtration of the three drill-in fluids. The results obtained showed that several polymers can be used to design KCl/Mn3O4 -drill-in fluids. The developed fluid had better thermal stability and filtration control compared to the drilling fluids that are currently used. This paper will discuss the results obtained and will demonstrate that the new fluid can save time and cost of drilling deep wells. Introduction Designing of drilling fluids for deep wells is challenging. Therefore, it has been the topic of many research studies. McCaskill and Bradford1 mentioned the factors that we need to consider when designing drill-in fluids. For example, formation permeability determines filtration characteristics. Temperature or water-sensitive formation determines the type of polymer and type of drill-in fluids needed. The authors also suggested that there are goals in designing drill-in fluids that we need to consider such as rheological properties to provide good carrying capacity and minimum filtration control loss. Carico and Bagshaw2 showed how different polymers are used for filtration control, viscosity modification and shale stabilization. There are different types of polymers that can impact the rheological properties and filtration of drilling muds. Some polymers lose viscosity at high temperatures because of their degradation and instability at harsh conditions such as xanthan gum and starch. Some polymers are not effective in salt solutions because salt inhibits hydration of polymers affecting their functions. Polymer compatibility with drill-in fluids is important to achieve good suspension, rheology and filtration control to ensure good hole cleaning and less formation damage. Abrams3 explained how designingdrill-in fluids depends heavily on the selection of a suitable size of weighting materials that will work as bridging materials. Once the solids invade the formation, they cannot be removed by natural flow. Abram stated that "the medium particle size of the bridging material should be equal to or slightly greater than 1/3 the median pore size of the formation." He also suggested using bridging materials at least 5 vol% of solids in the fluid. Ezzat4 showed the requirements for water-based drill-in fluids for horizontal wells such as physical stability, cutting transport, lubricity and formation damage control. The hydrostatic pressure of the drill-in fluids must be high enough to control the formation pressure, but not too high to avoid fracturing the formation and losing circulation. Using bridging materials is important to minimize filtrate invasion, mitigate fines migration and improve hole stability. In deviated wells, cutting accumulation and settling while drill-in fluids are in static motion is a major concern. The drill-in fluids should have good rheological properties to prevent solids and cuttings settling. The author also stressed the importance of conducting core flood testing to evaluate formation damage at reservoir temperature and pressure.
Under this climate of oil price and energy uncertainty, it is mandatory to limit the non-productive time (NPT) and achieve the highest levels of operational excellence. This is a key factor toward overcoming the evolving economic challenges, reducing budget and spending, and optimizing the return on investment. Worldwide, stuck pipe and borehole problems represent one major contributor into the NPT while drilling, reaming, tripping, casing and running completions. This NPT category becomes even more critical when dealing with shaly formations. Saudi Aramco constantly deal with offshore shaly formations in Saudi Arabia where stuck pipe and borehole problems contribute with over 24% to the overall drilling and workover NPT. Establishing best practices to minimize or prevent these problems will enhance the overall drilling performance and result in significant operating time reductions and cost savings. The major offshore re-entry operation challenges are first screened: formation instability, hole size, well trajectory, bottomhole assembly and experience and communication. The shaly formation rock nature is analyzed to understand the stressed shale instability root cause: mechanical and/or chemical. This diagnostic step establishes the formation shale properties and behavior. In relation to this information, three basic stuck pipe mechanisms (pack-off and bridging, differential sticking, and wellbore geometry) are discussed where the major contributing factors for each category are identified. This leads to the establishment of proactive recommendations and best practices. These practices will tackle the problem from different angles to construct an integrated solution. This includes drilling fluid design (rheology, filter cake, filtrate volume and properties, etc.), hole cleaning (rate of penetration, sweep pills, bottoms-up volume, etc.) and drilling parameters (trend analysis, flow rates, string motion, etc.). This paper will highlight the recommended practices and provide actual well examples where stuck pipe tendency was reduced in shaly formations.
Manganese tetraoxide (Mn3O4) has been recently used as a weighting material for water-based drilling fluids (Al-Yami et al., 2007). Mn3O4 particles are spherical, 1–2 µm in diameter, and have a specific gravity of 4.8 g/cm3. A mud (102 ± 5 pcf) was developed to drill deep gas wells. The filter cake formed by this fluid contained polymers (starch, XC-polymer, and polyanionic cellulose polymers), Mn3O4 and a small amount of CaCO3. Unlike CaCO3, Mn3O4 is a strong oxidizer and, as a result, HCl not recommended to be used to remove the filter cake. The objective of this work is to develop a new cleaning fluid to effectively and safely remove the filter cake that contains large amounts of Mn3O4. Various organic acids, chelating agents, enzymes, and a combination of these chemicals were tested up to 300 °F. Characterization of filter cake before and after soaking in several cleaning fluids were conducted using XRD/XRF/SEM techniques. Solubility of Mn3O4 was conducted using various acids and chelating agents at different temperatures up to 284 °F and 200 psi. The concentration of manganese in spent chemicals was measured using Inductivity Coupled Plasma (ICP). Extensive lab testing indicated that Mn3O4 particles in the filter cake were coated by polymeric materials that acted as a barrier. The coating material reduced the ability of cleaning fluids to remove filter cake. The efficiency of cleaning fluid was improved by soaking filter cake in a starch specific enzyme, and then applying the cleaning fluids. HCl, citric, and in-situ lactic acid were found to be the most effective fluids in dissolving Mn3O4 particles. This paper will discuss the characteristics of filter cake and the effectiveness of various cleaning fluids. New cleaning fluids were designed to remove Mn3O4 filter cake, while maintaining the integrity of the formation and well tubulars. Introduction Drilling horizontal/multilateral wells is utilized to enhance both hydrocarbon recovery and total well productivity from many types of reservoirs (Yildiz 2005 and Tronvoll et al., 2001). Drilling, workover and production operations may result in near-wellbore formation damage that in most cases cannot be prevented e.g. Pore plugging by calcium carbonate particles from drilling fluid, drilled solid particles, or particles from the formation (Ismail et al., 1994). Manganese tetraoxide was introduced to potassium formate drilling fluid back in 1995 to overcome the main drawback of potassium formate, which is the production of brine of density 1.7 g/cm3 (106 lb/ft3). Due to the partial solubility of barite in concentrated formate brines and the decision not to acidize prior well completion of the well, CaCO3 and barite were excluded as options to increase the density of the fluid. The most effective breaker fluid of the filter cake formed by this drilling fluid found to be 10 wt% citric acid with formate brine. (Sevendsen et al., 1995) Mn3O4 was introduced as a weighting material to oil-based drilling fluid due to the achievement of the very low plastic viscosity at the fluid density requirement and the ability to suspend the solid particles, Mn3O4, at lower fluid viscosity (Franks et al., 2004). In 2007, a water-based drilling fluid weighted with manganese tetraoxide and small amount of CaCO3 were developed. CaCO3 were added to control the filtration properties of the drilling fluid. The needs for using a drilling fluid with high rheological properties were achieved using manganese tetraoxide particles. (Al-Yami et al., 2007) Current approaches introduced to remove filter cake include the use of live acids, strongly buffered organic acids (Ali et al., 2000), chelating agents, oxidizing agents (Brady et al., 2000), enzymes (Butler et al., 2000, Al-Otaibi et al., 2000, and 2005), in-situ organic acids (Al Moajil et al., 2007), or combinations of these chemicals.
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