Recently observed production behavior in a maturing carbonate oil reservoir indicated that many production strings were getting plugged with solid scales, requiring tubing clean-out jobs. This is the main reservoir of a supergiant onshore carbonate oil field operated by ADCO since 1973. Some cases proved to be no more than calcium carbonate scaling following water breakthrough and the tubing blockage was successfully treated with acid washing. A number of plugged strings revealed that a non-mineral hard scale was the cause of the blockage. Upon analysis, such scales proved to have an organic composition rich in asphaltenes. While solvent washing was successful in removing the blockage, rapid reoccurrence was observed in many cases. The subsurface asset team embarked on a detailed reservoir monitoring and fluid compatibility study to establish causative factors. One of the aims of the study was to check a possible link between the asphaltenes deposition with a naturally occurring tarmat and a rich-gas injection pilot, both located in the severely affected part of the reservoir. This work revealed that although the severity of the problem is higher in the tarmat area, asphaltenes mobilization from the tarmat layer was not considered a realistic mechanism. Although PVT studies revealed that rich gas dissolution in the crude at reservoir conditions triggered asphaltenes instability and precipitation but occurrence of asphaltenes deposition in the field seemed unrelated to the rich-gas injection as the injected gas was moving in a different reservoir subzone. Most of the plugged strings were unlikely to have had gas breakthrough at the time of problem detection and no clear spatial relationship could be evidenced. A preferred explanation may be that asphaltenes precipitation is related to differences in crude oil composition within the studied reservoir. The reservoir might have seen successive oil influxes from two source rocks with wide distribution of mixing ratios. Asphaltenes originating from one of the source rocks might cause greater fluid instability even at the observed low concentrations. Production rate sensitivities indicated that asphaltenes blockage was retarded at higher production rates. Many asphaltenes dispersant/inhibitor chemicals were evaluated for effective tubing clean-out and preventing asphaltenes deposition. Some chemicals proved to be more effective in mitigation and prevention of asphaltenes deposition.
Asphaltene deposition is a significant flow assurance challenge in Abu Dhabi with over 100 onshore wells impacted. Until recently, there had been no applicable IoT device in the industry for direct measurement of the problem, which prompted the national oil company to sponsor a real-time sensor for asphaltene quantification. A second generation of that device is now available with enhanced capabilities and has been delivered in country, with preparation now ongoing for deployment across multiple onshore wells. Current ways of identifying asphaltene problems via accessibility checks with slickline are reactive, often too late, and thereby increase cost of clean-up and production losses. By quantifying in real-time the asphaltene as it flows through the wellhead, much earlier problem detection is made feasible. Such quantification has been made possible by resonating asphaltene molecules in applied magnetic and GHz fields as those molecules flow through the wellhead. The peak of the resonant signal is directly proportional to the asphaltene in the crude, with decrease in signal indicating potential deposition. Adding cloud-based, machine-learning to the system allows local in-country team to make efficient use of the data. First deployment of the resonant system in Abu Dhabi demonstrated the resolution of asphaltene signature was better than 0.1% when measured at atmospheric pressure and temperature. Subsequent testing in pressure vessels has shown remarkable independence to fluid pressure, even up to 2000 psi. Original system had a sensitivity sufficient to detect only the asphaltene peak. New system reveals multiple smaller peaks in the spectra which can be used for other flow assurance applications - for example, vanadyl porphyrins display a unique characteristic. By mixing solvents and precipitants with crude oil, we have confirmed that the asphaltene peak measures same value whether the asphaltene is in, or out, of solution which is precisely the feature that allows surface data to be representative of the cumulative precipitation downhole. The main advance, however, is that the system data will now be available on multiple wells in the field, which allows Operator to compare and contrast different flow assurance optimizations. This should lead to substantial cost savings in addition to minimizing well downtime and potential loss of production, all in alignment with the Operator’s 2030 "Smart Growth" strategy. The additional spectral information also allows spectrometer use for real-time analysis of water properties (dissolved solids) and rock typing (geochemistry). More generally, the system becomes a real-time platform for advanced chemical analysis at the wellhead. The result is an industrial Internet of Things (IoT) real-time monitoring device, the first of its kind, that not just detects asphaltene deposition but also makes possible the optimization of chemical programs by incorporating surface data into an integrated flow assurance management system.
As ADCO's oil fields mature, produced water increases. ADCO forecasts that the produced water may increase in the next 25 years as much as 10 fold (in excess of 600,000 BWPD by 2020 and more than 1,000,000 BWPD by 2027). On the other hand, in order to support the reservoir pressure, ADCO is sourcing brackish water from deep aquifers (D, S and U). The produced water is then disposed back into aquifer S. This practice has high financial and environmental costs:In order to strategically manage increasing volumes of produced water as the main oil producing reservoirs reach maturity, ADCO started pilots to re-inject untreated produced water in three fields in early 2000: Field 1 in 2002, Field 2 in 2010 and Field 2 in 2003.Positive pilot results in Field 1 led to field wide expansion of the Produced Water Re-Injection (PWRI) into one the oil bearing reservoirs and it was included in the Full Field Development Plan (FFDP).A pilot for re-injecting untreated PWRI is currently running in Field 2 for the past 16 months at a rate of more than 20,000 bwpd. Positive outcome so far led to raising funds to extend PWRI network to achieve re-injection rates of 50,000 BWPD into one of the oil bearing reservoirs in this field.The pilot for Field 3 was plagued with interruptions since the start caused by PWRI system material integrity issues which did not allow concluding so far whether untreated PWRI re-injection into one of the oil bearing formations is achievable. In order to address this situation, corrosion mitigation measures both for relevant surface facilities and downhole completions are being implemented and in parallel, an integrated coreflood testing/geomechanical properties study is on-going to assess the degree of treatment required to allow re-injecting produced water cost effectively in the most permeable oil bearing reservoir in this field.ADCO's approach to managing increased produced water rates through pilots and learning from rock matrices testing/studies shows that managing field wide PWRI systems in a cost effective and environment friendly manner is achievable if planned sufficiently in advance and executed properly.
Completion fluids, typically chloride or bromide brines, based on density requirements are used to control the well during some operations and remain either in the tubing until well is put on production or in the annulus above the packer for the duration of well life. Under normal conditions, the well casing is a closed system where the brine is protected from ingress of H2S/CO2 and oxygen. However, brines may be exposed to oxygen ingress from the surface through a leak at the wellhead, and /or to H2S / CO2 ingress through a potential leak through the packer, their dissolution in the brine, affecting significantly the corrosion resistance of the steel. In spite of its proven efficiency with martensitic stainless steels, sodium bromide based completion brines are quite expensive. To explore possible less expensive alternatives, without compromising corrosion resistance of the tubing, ADNOC Onshore conducted a comprehensive testing program to identify suitable, less expensive alternative brine systems with the same or improved corrosion behavior in well conditions. In the study, the general and pitting corrosion, and the Sulphide Stress Cracking (SSC) resistance of 13Cr and S13Cr samples in NaCl, NaBr and CaCl2 brines were assessed. Samples were tested for a period of 30 days in three brine systems, under inert conditions, under 1.6psi (6.5psi) H2S / 165psi CO2, at 120°C and under oxygen ingress conditions at 49°C, in an autoclave. Pitting and general corrosion were assessed using weight loss coupons, whereas the susceptibility to SSC was tested using C-ring specimens in accordance with NACE TM0177 - Method C, at stress levels of 0,2% of the material proof stresses. Relative pitting susceptibility of the steels under oxygen contamination of the different brine systems was also assessed by electrochemical polarisation tests, at 49°C. The most significant results obtained is that none of the steels presented SSC under all conditions and brine systems. For both alloys, in all test conditions, the general corrosion rates decreased in the order CaCl2 > NaBr > NaCl brines, the exposure to H2S/CO2 presenting 2 to 5 times higher corrosion rates as compared to the inert gas conditions, with the 13Cr alloy presenting higher rates in all conditions, as expected. Pitting was inexistent / negligible in all testing conditions for S13Cr. In sour environment and in oxygen ingress conditions, 13Cr showed relevant pitting in all brines. Under oxygen contamination, deeper and broader pits were observed in the NaCl as compared to the CaCl2 brine, while no pitting was found on NaBr brine specimens. Electrochemical polarisation tests showed that the pitting onset and the repassivation potentials were shifting towards the cathodic direction in the order NaCl, NaBr and CaCl2. The conclusions of the study is that chloride brine systems are a technically viable option for application with S13Cr, without introducing additional corrosion or HSE risks, leading to cost saving of $81MM over five years whereas for 13Cr, the use of bromide based brines cannot be avoided.
An active filter cake technology (AFT) was chosen to improve production performance in the tight reservoir following a comprehensive laboratory study to determine formation damage impact caused by previous non-damaging fluids (NDF). The AFT was successfully field trialed on two wells with production improvement vs. acid stimulated offset wells. This paper discusses laboratory data and improved field productivity. It documents reduction of torque/drag with increased rate of penetration without using a lubricant during drilling. Comprehensive laboratory testing to identify origins of deficient production was completed by thoroughly reviewing drilling and completion practices, and completion type implemented. Compatibility of base brine with formation water; formation damage impact of drilling fluids used in reservoir and effectiveness of hydrochloric acid (HCl) solution pumped through coiled tubing to destroy the filter cake constituted the first phase of the investigation. Assessment of several fluids capable of mitigating concerns was performed in the second phase. The optimization and customization of candidate fluids to address all challenges was the third phase. Last phase consisted of field trials and assessment of production results. Testing identified a potential incompatibility of calcium chloride brine and the formation water. The brine was replaced with monovalent halides brine. The previous NDF system exhibited elevated filtrate volume and a high concentration of acid insoluble materials which together significantly impacted productivity. Review of the completion operation and laboratory results proved filter cakes of reservoir drill-in fluids (RDF) cannot be homogenously and entirely removed with HCl solution using coiled tubing. Only less than 50% of the wellbore length can be accessed with coiled tubing and treated with acid. The acid treatment dissolved less than 10% of filter cake when sumulated field conditions in the laboratory. Likewise, the filter cake breaker cannot be implemented on barefoot completion as its volume is totally lost to the formation after breakthrough before complete filter cake dissolution occurs. The study recommended AFT with 100% organophilic bridging materials. The AFT was successfully field trialled in two wells. Post analysis of drilling parameters with AFT exhibits lower torques without addition of lubricant compared to previous fluid along with 186% increase in average rate of penetration which saved 79 hours of ILT/well. Production kicked-off without assistance from lighter fluid (N2 gas) or stimulation showing promising results compared with near-by wells. The 100% organophilic bridging materials were used for first time in field. It proved acid stimulation can be eliminated for the tight reservoir while improving the oil production rate compared to the offset wells. In addition to inherent productivity improvement characteristics, AFT is appropriate where cheesing and greasing of RDF are common problems with lubricants. AFT demonstrates reduced torque without lubricant addition in extended horizontal deviated wells and excellent production while eliminating post stimulation.
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