This paper will present a statistical risk based approach to proactively predict casing leaks using Electromagnetic (EM) corrosion logs. The corrosion growth of downhole casing hotspots (areas likely to develop casing damage) is monitored to develop expectancy calculations of a typical well's remaining life. Currently the predominant technology used for casing integrity measurement and monitoring are the EM corrosion logging tools. While this technology has provided a step-change in the ability to measure and monitor corrosion, the findings are not usually conclusive and need to be integrated with other data to make qualitative assessment. This is largely due to the nature of the tool's output where averaging is used to assess metal loss rather than direct measurement of the spot where metal loss is taking place. In other words, 50% average metal loss could mean a failure if one part of the casing is completely gone and the other is intact; or 50% metal loss is distributed evenly across the 360 degree circumference of a casing with no leak. This wide range of possibilities and uncertainty has made it extremely challenging to both interpret and analyze EM corrosion logging data. Establishing consistent criteria to classify the corrosion severity and confidently decide on the need to workover the well or not is a challenge to all field operators worldwide. A probabilistic approach was introduced to improve EM corrosion logs' data interpretation. More than five hundred data points were collected and statistically analyzed to build a probability of failure model as a function of EM average metal thickness loss. These models were used to delineate a dynamic safe window of the average metal loss value across multiple casings.

In Saudi Arabia, conventional oil reservoirs have been treated using conventional stimulation methods. The challenge is that many of the formations now are tighter and require improved stimulation methods. Fracturing is a major topic discussed in the industry as of late and as such, using it in this formation will serve as a trial to shift from conventional stimulation methods to fracturing when facing tighter formations.This particular acid frac was performed in a tight carbonate formation. The chosen well is a newly drilled trilateral producer completed with a multistage frac completion in the motherbore and will serve as a pilot well for this reservoir in the area. The acid frac was a seven stage completion utilizing hydraulic fracturing. Several methods using pressure and injection were used to determine reservoir fracturing response and petrophysical properties. This paper will discuss the first multistage acid frac performed in an oil producer in Saudi Arabia. It will examine the entire process of candidate assessment, job preparation, and execution. In addition, the paper will discuss challenges faced, solutions taken, and the post-decision results. The paper will show how an injectivity test performed pre-and post-frac was used as a benchmarking tool to analyze the effectiveness of the frac. Finally, we will discuss the flow back of the well, initial results, lessons learned, and optimization of future jobs.

In Saudi Arabia, conventional oil reservoirs have been treated using conventional stimulation methods. The challenge is that many of the formations now are tighter and require improved stimulation methods. Fracturing is a major topic discussed in the industry as of late and as such using it in this formation will serve as a trial to shift from conventional stimulation methods to fracturing when facing tighter formations. This particular acid frac was performed in a tight carbonate formation ranging in permeability from 1 - 2 md. The chosen well is a newly drilled tri-lateral producer completed with a multi-stage frac completion in the mother bore and will serve as a pilot well for this reservoir in the area. The acid frac was a seven stage completion utilizing hydraulic fracturing. Several methods using pressure and injection were used to determine reservoir fracturing response and petrophysical properties. This paper will discuss the first multi-stage acid frac performed in an oil producer in Saudi Arabia. It will examine the entire process of candidate assessment, job preparations, and execution. In addition, the paper will discuss challenges faced, solutions taken, and the post-decision results. The paper will show how an injectivity test performed pre- and post-frac was used as a benchmarking tool to analyze the effectiveness of the frac. Finally, we will discuss the flowback of the well, initial results, lessons learned, and optimization of future jobs.

This paper presents a comprehensive review of a successfully employed methodology used for utilizing variable speed drive (VSD) with electrical submersible pumps (ESPs) to boost the oil production in a remote desert field in Saudi Arabia. The successful employed methodology was done through a structured test program for VSD frequency jackup. The program was designed to overcome the back pressure in the trunk line connecting this field and others to a Central Processing Facility where the downstream pressure of the wells are fluctuating within 60 psi with a maximum back pressure of 865 psi. The ESP frequency on the producers in this field was jacked up to a frequency measured below the maximum allowable operating pressure (MAOP) of the trunk line. The maximum frequency was adjusted through recording the deadhead pressure (DHP) of the ESP at different frequencies and selecting a new running frequency, which is the frequency recorded at the closest pressure below the MAOP of the trunk line. This test was done to boost the production from each producer while maintaining integrity of the trunk line. The production gain indicates that increasing the ESP frequency via the VSD is a very valuable tool. This test was done on 15 producers equipped with intelligent field gadgets in which the data is transmitted to the production engineer's desktop. Every producer is equipped with an ESP unit with a sensor and VSD, in addition to a multiphase flow meter (MPFM) unit for rate measurements. The VSD, which is designed specifically for use with the ESP, has been available for several years. The utilization of the VSD as an effective tool to increase the production from the ESP is very well documented in the oil industry. The ability to vary the operating speed of the ESP through the VSD greatly expands the production range of the ESP. In this paper, the methodology and the structured test program implemented in the (R) field during the frequency jack-up campaign utilizing the VSD on the producers will be discussed, in which the post-test and pretest results will be shared and examined. Although, the long-term effects of operating the ESP pumps on high frequency and high amps for extensive periods of time will not be covered in this case study.

This paper presents the success story of an innovative milling operation on a stuck-closed tubing master valve performed with electric line technologies. This field application has resulted in restoration of well accessibility, enabled well control, and saved costs related to rig intervention. The paper also documents lessons learned and recommends proper operational procedures related to future similar rigless operations, specifically with regards to well control and barrier philosophy. A stuck-closed surface valve in a live well is treated with extra caution as it presents a serious and challenging well control issue. Such a situation often calls for immediate intervention to restore well accessibility and reestablish well integrity barriers. The stringent well control requirements of the oilfield operator make the operational design and corresponding job execution even more challenging. In this case, Well-A is a land based vertical oil well on which the master gate valve was stuck and non-functional in the closed position. The pressure bellow the valve was last measured to be 1200 psi, a relatively high shut-in wellhead pressure compared to other offset producers in the same field. The wellhead was equipped with two carbon steel master gate valves, in addition, to the swap valve. The lowermost gate valve is the stuck valve, hence, preventing access to the well. Several attempts to repair and grease the valve body and stems were unsuccessful. Accordingly, the oilfield operator has decided to mill the gate valve, secure the well, and then replace the entire tree. The uncertainty in the well pressure below the master valve posed a significant operational risk. This is due to the impact of well fluid pressure force on the electric line rig-up after the gate valve is milled. Therefore, job planning, design, and execution were guided by a risk based and comprehensive contingency plan that accounted for all probable well control scenarios. The rig-up consisted of coiled tubing flanged risers, annular blowout preventer, Shear/Seal ram, and wireline blowout preventer in order to ensure the presence of adequate well control barriers throughout the operation. Adhering to a ‘safety first’ attitude, the operation was concluded successfully and met its said objectives. The successful massive undertaking of such critical well intervention operation has marked a new milestone in rigless well interventions.