Sand in Saudi Arabia is easily accessible through surface mining or excavating large dunes that are API approved, but like many sands around the world, lacks the necessary strength for fracturing high stress formations. To exploit the sand, a novel engineered workflow, enabled by the flow channel fracturing technique was established for qualifying and implementing Saudi Arabian sand to fracture stimulate the tectonically complex ultra-tight "T" carbonate formation. Channel fracturing does not depend on the proppant pack to provide conductivity, rather on the creation of stable, open flow channels. Therefore, carefully selected sand that can keep the channel structure open under stress can be a viable material to replace up to 80% of the ceramic proppant materials. The local sand used was qualified through unique lab testing procedures to understand the pack behavior under stress, the pillar erosion under stress, and the effects of stress on long-term conductivity. Once qualified, a design methodology was applied to optimize the fracture geometry and pillar placement for the initial field test in Well-A, a horizontal lateral where high strength proppant (HSP) is traditionally used. A total of six channel fracturing stages with local sand — 40% of the total stages — were placed as per design in two sections of the 15-stage lateral along with four conventional and five channel fracture stages using HSP. A multi-month cleanup and well test period resulted in Well-A being one of the best producing wells in the basin — 26% higher initial production than the next best well. A production log showed sand stages to be producing an average of 15% higher total production than HSP stages. An oil tracer analysis revealed sand stages produced an average of 62% more condensate than HSP stages. This initial production response confirms at least par production with no detrimental effects for channel fracturing with local sand compared to techniques using HSP, with the potential for improved production. This qualified and field tested completion methodology allows for the potential replacement of a significant portion of imported ceramic proppant with locally sourced sand, an abundant and accessible resource inside the Kingdom of Saudi Arabia and beyond. The benefits of this technology include cost reduction, placement improvement, at least par production and the maximizing of in-country content and value.

In today's drive to improve well production and performance, more innovative methods are continually being implemented to enhance well productivity and reservoir management. By increasing reservoir contact and applying fit for purpose technologies, increased production can be attained at lower drawdown. This can be accomplished by the effective implementation of multilaterals wells. In multilateral wells equipped with active downhole control valves and downhole measurement-devices, monitoring and managing the production from each lateral is achievable. These capabilities will enhance well performance and allow better sweep; hence better recovery. This paper describes the design, completion, commissioning, and operational experience of the world's first well equipped with intelligent completion combined with fiber-optic monitoring capabilities. Well-A is a trilateral MRC well with more than 5 km of total reservoir contact. The monitoring system for each lateral includes an optical flowmeter and pressure and temperature gauge. The readings of the flowmeter were compared to the readings against the conventional testing facilities. Production tests were conducted with various combinations of downhole valve positions for each of the three laterals to determine the optimum combination. The pressure and temperature gauges yielded excellent measurements as they were verified against conventional pressure and temperature measurements. The downhole flow rate measurements were assessed against conventional rate measurements and demonstrated acceptable results across most downhole valve positions. A comprehensive review was conducted on the optical flow meter capabilities to provide better understanding; hence, facilitate further enhancement to the technology and better production optimization capabilities. The review was utilized to develop a new system that provides better capabilities across all valves positions. Background The adoption rate of optical sensing technology for in-well permanent monitoring has accelerated dramatically since it was first introduced more than a decade ago. Today, most of the common electronic-based technology measurements for in-well permanent reservoir monitoring have a commercially available optical equivalent; such as pressure, temperature, seismic, and flowmeters. In fact, optical monitoring has exceeded the functionalities of conventional downhole measurement devices. The new fiber-optic devices provide various measurement capabilities such as Distributed Temperature Sensing (DTS), Array Temperature Sensing (ATS), and non-intrusive single and multiphase flowmeters.

Meckel’s diverticulum MD is the most common congenital deformity of the gastrointestinal tract. It has a very low reported incidence. We reported a 9-year-old child complaining of symptoms of small bowel obstruction. He had no medical or surgical history. There is no signs of peritonitis and appendicitis. Simple abdominal X-ray diagnosed the obstruction, during surgery we found an MD located 30 cm from the ileocecal valve, fibrous band may be as complication for MD to the anterior abdominal wall at the umbilicus, the small intestines were wrapped around the band, causing the obstruction. The MD and the band were excised with end-to-end anastomosis. We diagnosed our case during surgery. Early surgery is important to preserve bowel from gangrene or necrosis. The patient’s well-being improved, and he was discharged from the hospital in good condition.

In today's drive to improve well production, more innovative methods are continually being implmented to enhance well productivity and reservoir management. Remote monitoring and interactive control are two such methods that are more frequently employed to derive more value from wells. In Saudi Arabia, the world's first maximum reservoir contact (MRC) well, using Intelligent Well Systems and fiber-optic monitoring to maximize production performance was implemented. This paper discusses the implementation of remote monitoring and interactive control systems on Well-194, which was drilled as a tri-lateral MRC well with 4.2 km (2.61 mi) of total reservoir contact. The Intelligent Well System utilized feed-through production packers to isolate each of three laterals in the motherbore. Three remotely operated downhole chokes were installed to independently control flow from each lateral for the purpose of optimizing overall well production. This control extends the production plateau while maximizing reservoir drainage. The fiber-optic monitoring system enables remote monitoring of key production parameters, including pressure, temperature, total flow rate and water cut from each of the laterals, used to determine optimum downhole choke settings. Finally, the well was implemented as "ESP Ready" with 7″ tubing and a Deep-Set SCSSV to enable subsequent installation of a thru-tubing ESP to further improve production. Ultimately, this configuration resulted in a well capable of producing at a very high rate with low drawdown for an extended period of time. This strategy will result in a long-term sustained rate while optimizing the reservoir drainage process. This paper will review the lessons learned and key issues around implementing this type of "Next Generation" well completion system. MRC Well Overview The definition and benefits of MRC wells have been well defined1, however for the purpose of this paper a short description and application of this technology is important. In lower permeability carbonate facies environments, significantly extending wellbore reservoir contact yields significant enhancements in the well's Productivity Index. The length a single horizontal lateral can be drilled is limited by drilling constraints such as Torque and Drag as well as productivity issues around flowing back, cleaning up and getting significant production from excessively long horizontal wells. Multi-Lateral technology has been utilized to extend reservoir contact while not exceeding drilling and production constraints. Typically a MRC well consists of three or four single open hole laterals drilled from a single "Motherbore". Naturally, each single lateral acts as a single well with variances in permeability and productivity identified from lateral to lateral. Intelligent Well Systems can be installed in the motherbore of an MRC well to mitigate the risk associated from variances in reservoir parameters that can lead to early water breakthrough and poor ultimate recovery. In the case of Well - 194, the Intelligent Well System consisted of three separate downhole valves and monitoring stations that independently monitored the production rate and water cut from each lateral and then enables remote isolation of each lateral without intervention. (See Figure 1)

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