The increasing demand for energy has extended the development horizon towards relatively tighter formations all over the world. In Saudi Arabia, hydrochloric and organic acids have been extensively used to enhance well productivity or injectivity in low permeability formations. However, the use of these acids was associated with severe formation damage, which is attributed to acid/oil emulsions and/or asphaltene precipitation in some of the low permeability carbonate reservoirs. Consequently, a detailed study on different factors that influence the acid/oil emulsion and asphaltene precipitation mechanism was carried out for these reservoirs. Several compatibility studies were conducted using representative crude samples and different acid systems such as HCl and formic acid. The experiments were conducted at various temperatures up to 240°F using HP/HT aging cell for both live and spent acid samples, where some of the experiments included anti-sludge, iron control and demulsifier chemical additives. In addition, another set of experiments was performed in the presence of ferric ions (Fe3+). The total iron concentration in these experiments varied between 0-1,000 ppm. The results obtained from this study have revealed that the acid systems were not compatible with several representative oil field samples. The amount of asphaltene precipitation and the stability of formed emulsions increased significantly in the presence of ferric ions. Several wells have already been acidized and damaged prior to initiating this study. This paper discusses different tests conducted to identify, quantify and treat acid-oil emulsions/asphaltene precipitation in tight carbonate reservoirs. It also provides details of a special solvent treatment fluid recommended to revive dead wells which were damaged by acid-induced emulsion and asphaltene precipitation.
Downhole gauges for ESP systems typically use the motor power cable for communicating data to surface. This type of gauge technology, also known as "Comms on power," has been in use for many years and has become a reliable method for monitoring pump and well performance. Downhole data acquisition also delivers benefits in reservoir management where continuous data from the well is required. Any loss of this downhole data has a significant impact to accurately understanding the well performance and reservoir recovery.Current gauge technology is susceptible to problems when the insulation on the motor cable ages or is damaged. This means that the gauge signal will be lost when a ground fault occurs, even if the ESP motor continues to drive the pump and the gauge itself is undamaged. Current ESP gauges also typically provided slower data rates than permanent gauges that have dedicated instrument lines to surface.In such situations there are two options to recover the downhole data; conventional data acquisition using wireline or workover to repair the ground fault. Both required additional operational cost. Furthermore, any opportunities to obtain improved ESP monitoring and continuous data acquisition for reservoir management are gone.Saudi Aramco has been engaged in several years of technology trials carried out in Saudi Arabia leading to a successful field trial of a new downhole sensor system. Saudi Aramco's drive for continuous data when the ESP has experienced a ground fault has been the catalyst for the support given to this system. The system was installed in April 2013 in the Khurais field and is currently still running today -the system was confirmed to be fully functional in ground fault conditions. This paper presents the new technology, the history of trails and the installation, outlining the potential for future use.
This paper provides information on the journey and lessons learned from one well’s acid MSF from the required lab design, through on-site fluids’ QA/QC findings, to the 4 days of flow back sample analyses indication. Several pre-job lab assessments were conducted to: Optimize the diversion fluids rheology, assure sufficient acid corrosion inhibition, and eliminate the incompatibility issue between all pumped fluids and the reservoir acid sensitive crude oil. Additionally, on-site QA/QC critical findings for each stage fluid resulted in taken corrective actions for assured acceptable concentration and stability of mixed acid recipes and the adequacy of fracturing fluid viscosity. The 4 days of flow back samples analyses revealed the need for a longer cleanup time. In addition, ion composition of flowback samples were used to identify areas of improvement and enhancement in fracturing fluid design. The successful massive multistage acid fracturing was achieved with over a two-fold increase in production rate. A major part of the success is attributed to a scheme of the fluid’s optimization, quality control, on-site QA/QC and cleanup monitoring progress. In addition, on-site fracture treatment evaluation for each stage individually has a major impact on operational success utilizing pressure sensors response and fracturing simulation software. Finally, a comprehensive analysis for an acid fracture job and the lessons learned from this operation will be shared. The journey of lessons learned started from the lab to the field, and back to the lab, with strong guidelines for all future acid fracturing jobs in similar oil fields
Electric Submersible Pumps (ESPs) is very popular artificial lift systems to boost oil production now days. Home ofmany ESP installations, with high frequency of change outs per year and with the harsh production environment, a development of ESP technologies to reduce change-out time and improve run life is keep ongoing. These technologies address business challenges timely in a proactive approach. Currently deployed ESPs require a time-consuming rig installation on jointed tubing. With several factors such as: an average run life of three years for ESPs, a rig-based change-out time of up to two weeks offshore, and an uncertainty of when a rig can be scheduled; the need for a more rapid rigless solution is critical for future operations. Majority of the ESP installation are completed as part of tubing completion and deployed by drilling rig which requires high spending to recover the well during ESP replacement. Several types of technologies to deploy ESP rig-lessly were introduced into industry to optimize the retrieval and deployment cost during ESP replacement. Limited success story was recorded and open more thought to overcome the challenges. The first worldwide new reliable cable rigless deployed electrical submersible pumping (ESP) system was successfully installed and put on production. What makes this system unique concept and the first worldwide of its kind are two main components. The first component is the innovative cable hanger design that insures total cable isolation while providing a non-restricted flow through the tubes that are built into the body of the spool. The second component is the specially designed and manufactured CT from selected material that has high resistance to H2S and CO2 and it was made exactly fit the ESP cable providing full protection from corrosive wellbore fluid. This design aimed to boost production of oil wells with lower ESPs installation and replacement cost. The new system eliminates the need for and expensive rig to replace the ESP and accelerate production restoration. This system will be a great addition especially for offshore environments where not only the rig intervention costs are expensive, but also limited rig availability can delay ESP replacement. This paper will share the concept, design, field implementation planning and technical challenges, lesson learnt during preparation and installation of this first of kind system.
The increasing demand for energy has extended the development horizon towards relatively tighter formations. However, experience has shown that the most successful technique to optimize production from these tight carbonate formations would require multistage acid fracture stimulation treatment. Generally, laboratory tests, computer simulation and technical expert opinions yield optimistic results which are not always replicated in the field due to the absence of strong QA/QC follow-up. This field support was considered critical for a recent multi stage acid fracture treatment which involved many variables and fluid additives in an onshore Saudi Arabia multi-lateral well. This report will discuss the pre-job laboratory tests and fluid optimization process which included core flooding, compatibility, stability, and rheology tests. In addition, this paper will outline the QA/QC process adopted throughout the various operational stages and provide flowchart as recommendations for subsequent multistage acid fracture treatments in the field. Also presented is a case study from the first successful oil field multistage acid fracture treatment in Saudi Arabia. Laboratory results obtained reflected the negative impact of increased salinity on the crosslinked viscosity. In addition, a new low temperature-instant crosslinker was evaluated as an alternative which resulted in higher viscosity and faster break time. Further laboratory tests showed the sensitivity of the emulsifier used to mix emulsified acid and this led to corrective changes to the on-site mixing process. These and many other operational adjustments enabled bridging the gap between laboratory design and field implementation, thereby ensuring a successful acid fracturing treatment.
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