Oil production decline and excessive water production are prevalent in mature fields and unconventional plays, which significantly impact the profitability of the wells and result in costly water treatment and disposal. To seek for a sustainable development of those wells, reducing the operation cost and extending their economic lives, this paper presents a method of synergistic production of hydrocarbon and electricity, which could harvest the unexploited geothermal energy from the produced water and transfer heat to electricity in the wellbore. Such method is cost-effective, since it does not require any surface power plant facility, and it is replicable in numerous wells including both vertical wells and horizontal wells. By simultaneous coproduction of oil and electricity, the value of existing assets could be fully developed, operation cost could be offset, and the economic life of the well could be extended.
This recently proposed method incorporated thermoelectric power generation technology and oil production. In this method, electricity could be produced by thermoelectric generator (TEG) mounted outside of the tubing wall under temperature gradient created by produced fluid and injected fluids. The aim of this paper is to illustrate the economic practicability of oil-electricity coproduction by using thermoelectric technology in oil wells based on previously proposed design. We examined the technical data of high water-cut oil wells in North Dakota and collected required information with respect to performance thermoelectric power generations. Special emphasis was placed on the key parameters related to project economics, such as thermoelectric material, length of TEG and injection rate. Sensitive studies were carried out to characterize the impact of the key parameters on project profits. We showed that by simultaneously production of oil and electricity, $234,480 of additional value could be generated without interfering with oil production.
The proposed method capitalizes on the unexploited value of produced water and generates additional benefits. This study could provide a workflow for oil and gas operators to evaluate an oil-electricity coproduction project and could act as a guidance to perform and commercialize such project to balance parts of the operation cost and extend the life of the existing assets.
Kumar, Ajay (GNPOC Sudan, ONGC Videsh Ltd) | Ibrahim, Yasir (GNPOC Sudan) | Atta, Badrelddin (GNPOC Sudan) | Singh, Vijendra (ONGC Videsh Limited) | Musa Elmubarak, Omer (GNPOC Sudan) | Razak, Chik Adnan Abdul (GNPOC Sudan) | Tripathi, Bamdeo (ONGC Videsh Limited) | Vidyasagar, V. (ONGC Videsh Limited)
Produced water is an inextricable part of the hydrocarbon recovery processes. Safe and environmentally benign disposal of produced water is a major concern for all the oil fields across the world in the present low cost and stringent environmental & statutory compliance era. Many technology available in the market to treat produced water oil contaminants but economical treatment of heavy metal content is still a great challenges for oil industries for safe disposal.
Therefore, New innovative technology i.e. Reed bed technology has been adopted in Heglig field of Sudan to treat the produced water and heavy metal economically through phytoremediation. After successful implementation in Heglig oil field, it is being implemented in other surrounding oil field also.
It is probably a world largest Phytoremediation/Bio-remediation system using Reed Bed technology operating successfully for last 15 years. It is environmental friendly, solar energy driven clean up techniques. This paper not only elucidate, how reed bed removes oil contaminants and heavy metals but also provide clear picture of how this project provide shelter for flora, fauna, other species that help to maintain ecological and environmental balance. Research has also demonstrated that reed-bed technology is feasible and resilient in treating oil produced water
Case studies of mill-out operations in the Permian Basin which evaluate chemical programs and processes used. Results show how existing processes and chemicals used or lack thereof, can affect equipment and undo the preventative chemical treatments used during the hydraulic fracturing process.
The study looks at field water testing performed during various mill-out operations and considered workover rig vs coiled tubing, equipment set up, water & chemicals used, and operational challenges. Water analyses were completed on the injection water and returns at various intervals of the mill-out. Effectiveness of chemical treatment was also monitored when biocide was used.
Field case studies of horizontal wells for two operators in the Permian Basin are presented. Wells were milled-out utilizing workover rigs or coiled tubing units. Testing results show the impact of equipment setup and operations process on the water quality and efficiency of the chemicals used. Water fouling was prevalent in all cases, with coiled tubing jobs showing the highest degree of water contamination and chemical inefficiency. Changes in the water treatment program during operations showed significant improvement and sustainable results. Potential corrosion of the work string due to water fouling and water composition were also observed. The effects of changes to chemical dosages were also monitored. This was important because it identified operational improvements that can reduce equipment replacement costs, reduce chemical overuse and help protect wells from fouling due to high bacteria.
These case study provides a comprehensive review of mill-out operations, which provides guidelines for improving chemical efficiency and potential of extending life of the work string.
Hazra, Suchandra (Dynachem Research Center) | Madrid, Vanessa (Dynachem Research Center) | Luzan, Tatiana (Dynachem Research Center) | Van Domelen, Mark (Downhole Chemical Solutions) | Copeland, Chase (Downhole Chemical Solutions)
This paper provides a detailed evaluation of the impact that field source water chemistry has on the performance of friction reducers being used for hydraulic fracturing. In this research, correlations are established between friction reducer performance and source water chemical composition, allowing operators to shorten the learning curve within their fracturing operations, use the most appropriate fluid systems, and potentially mitigate job failures. Extensive testing has been conducted to evaluate friction reducer performance in the presence of different ionic components such as calcium, magnesium, iron and chloride. Performance testing was determined by varying individual ions, as well as using source waters from multiple field locations having total dissolved solid (TDS) levels of well over 100,000 ppm. Testing parameters included friction reduction, hydration rate via viscosity, and rheological characterization for viscosifying-type friction reducers. Principal component analysis was used as statistical tool to characterize the variation in water chemistry and to establish its relationship with friction reducer performance.
A so-called perturb-and-observe (P&O) algorithm is adapted for a novel centrifugal pump to continuously optimize the point of operation. The novel pump coalesces and increases the size of oil droplets in the produced water, resulting in a unique relationship between the coalescing effect and the point of operation, and allowing for the successful implementation of the P&O algorithm. The algorithm was implemented in two different setups, one measuring the dropletsize distribution between the hydrocyclone and the pump, and the other measuring the oil concentration downstream of the hydrocyclone. The latter was considered the most robust because it required no prior knowledge of the system. Nonetheless, both setups achieved satisfying results and compared favorably with a third setup, where the optimal point of operation was predicted using measurements of the upstream produced-water characteristics. Introduction During oil and gas production, significant amounts of water are often produced along with the hydrocarbon mixture. Coproduced water, usually called produced water, can be a considerable source of pollution because it contains combinations of organic and inorganic materials that can lead to toxicity. Because of this, produced water is cleaned before being discharged into the sea or reinjected into a reservoir (Fakhru'l-Razi et al. 2009). Subsequently, in combination with other treatment technologies, hydrocyclones are often used to remove the remaining dispersed oil from the produced water.
Moore, Joseph (DowDuPont Industrial Biosciences) | Massie-Schuh, Ella (DowDuPont Industrial Biosciences) | Wunch, Kenneth (DowDuPont Industrial Biosciences) | Manna, Kathleen (DowDuPont Industrial Biosciences) | Daly, Rebecca (Colorado State University) | Wilkins, Michael (Colorado State University) | Wrighton, Kelly (Colorado State University)
Hydraulic fracturing presents an ideal breeding ground for microbial proliferation due to the use of large volumes of nutrient-rich, water-based process fluids. Bacteria and/or archaea, when left uncontrolled topside or in the reservoir, can produce hydrogen sulfide, causing biogenic souring of hydrocarbons. In addition, microbial populations emerging from the downhole environment during production can colonize production equipment, leading to biofouling, microbially influenced corrosion (MIC), produced fluid separation issues, and HS&E risks. Mitigating these risks requires effective selection and application of biocides during drilling, completion, and production. To this end, a microbiological audit of a well completion operation with the objective of determining the effectiveness of a tandem chlorine dioxide (ClO2) and glutaraldehyde/quaternary ammonium (glut/quat) microbial control program was carried out. This paper describes the rationale behind selection of sampling points for a comprehensive microbiological field audit and provides the resulting critical analysis of biocide efficacy in the field using molecular assays (qPCR, ATP) and complementary culturing techniques (microtiter MPN and culture vials—commonly termed "bug bottles").
Due to the comprehensive nature of sampling and data collection, it was possible to make much more applicable and relevant observations and recommendations than it would have been using laboratory studies alone. First, multiple sources of microbial contamination were identified topside, including source waters, working tanks, hydration units, and guar. Additionally, critical analysis of biocide efficacy revealed that ClO2 treatment of source water was short-lived and ineffective for operational control, whereas glut/quat treatment of fracturing fluids at the blender was effective both topside and downhole. Analysis of the microbial load at all topside sampling points revealed that complete removal of ClO2 treatment could be offset by as little as a 10% increase in glut/quat dosage at the blender. This is a highly resolved microbiological audit of a hydraulic fracturing opration which offers new, highly relevant perspectives on the effectiveness of some biocide programs for operational control. This overview of biocide efficacies in the field will facilitate recommendations for both immediate and long-term microbial control in fractured shale reservoirs.
Ma, Yingxian (Southwest Petroleum University) | Ma, Leyao (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Lai, Jie (Southwest Petroleum University) | Zhou, Han (Downhole Service Company, CNPC Chuanqing Drilling Engineering Company Limited) | Li, Jia (Downhole Service Company, CNPC Chuanqing Drilling Engineering Company Limited)
We prepared physically linked allyl alcohol polymer/polyacrylamide double network hydrogels via onepot strategy. These double network supermolecular fracturing fluids were found to have a better viscosity at high temperature compared to the conventional polyacrylamide systems. After testing with a rheometer, the fluid viscosity could stay 320 mPa s at 150 C under 170/s shear rate. With NMR and FT-IR results' help, we determined that abundant polar groups of chains were still free, which could complex ions to keep, even enhance the chain stability. Thus, these double network systems showed excellent salt resistance with the non-covalent interactions and physical entanglements, and the viscosity of the allyl alcohol polymer/ polyacrylamide system did not drop but increase. The viscosity in high salinity could increase nearly 40 % compared with the initial situation. Overall, the novel fracturing fluid system could maintain a high viscosity and better rheological properties under high salinity and showed excellent high-temperature stability, to make up the lack of fracturing fluid at this stage. It is expected to potential fluid issues caused by low water quality and harsh downhole temperatures were resolved or mitigated.
Li, Ningjun (Haimo Technologies Group Corp.) | Zheng, Ziqiong (Haimo Technologies Group Corp.) | Guo, Peihua (Haimo Technologies Group Corp.) | Hao, Xipeng (Haimo Technologies Group Corp.) | Chen, Bingwei (Haimo Technologies Group Corp.) | Ren, Yao (Haimo Technologies Group Corp.)
Ordos basin is known for its tight sandstone formations and fracturing has been the most effective approach to improve production[
To successfully treat and reuse flowback fluid in Ordos basin, two major obstacles have to be overcome: First, in the fracturing process, the local common practice is to add the entire designed amount of gel breaker at the end of propant pumping job, to avoid sand plugging and sanding out. This incorrect, but common practice results in incomplete breaking of gel of the frac fluid, which inevitably flows back leading to greatly increased difficulties in flowback fluid treatment. Secondly, organic boron crosslinking agent is widely used as crosslinking agent in the guar fluid system in this area. As boron compounds are extremely difficult to be removed during flowback fluid treatment, proven treatment methods alone cannot make the treated water reusable in making new frac fluids.
Technology and processes were developed to manage four key factors that affect the performance of guar frac fluid configured with treated flowback fluid: a) Metal ions, b) Bacteria, c) Breaking agent, d) Crosslinker. Mobile units developed in association with treatment processes and agents also help avoid secondary pollution from the transportation of fresh and flowback fluid. In 2017 and first quarter of 2018, more than 15,000 cubic meters of flowback fluid have been successfully treated and reused. One third of the treated water was guar frac fluid and was reused in making new frac fluid, reducing the need for fresh water significantly. Fracturing service company conducted tests on the treated water and found that the performance of the fluid configured with the treated water completely satisfy the requirements of the SY/T6376-2008 "General Technical Requirements for Fracture Fluid" and SY/T 5523-2016 "Oilfield Water Analysis Method" standard. Frac fluid configured with the treated water was successfully applied to the stimulation jobs of horizontal wells, resulting in double savings to the operators: purchase of fresh water and transportation of flowback fluid (to treatment centers) and fresh water, also avoided secondary environmental impacts such road safety hazard and fluid seepage.
With the treatment and reuse of flowback fluid, savings up to 8% of total frac costs per well were observed which could lead to 100+ million RMB within 2018 alone. Most importantly, the technology can effectively relieve environmental pressure and reduce the need of fresh water which is a scarce in this area.
Wu, Di (Daqing Oilfield Engineering Co., Ltd.) | Liu, Wenjie (Daqing Oilfield Engineering Co., Ltd.) | Cai, Xun (Daqing Oilfield Engineering Co., Ltd.) | Meng, Xiangchun (Daqing Oilfield Engineering Co., Ltd.) | Yang, Yuepeng (Daqing Oilfield Engineering Co., Ltd.) | Lin, Sen (Daqing Oilfield Engineering Co., Ltd.) | Zhang, Shaohui (Daqing Oilfield Engineering Co., Ltd.) | Wang, Cong (Daqing Oilfield Engineering Co., Ltd.) | Zhang, Huiping (Daqing Oilfield Engineering Co., Ltd.) | Li, Yinghui (Daqing Oilfield Engineering Co., Ltd.) | Zhao, Fengling (Daqing Oilfield Engineering Co., Ltd.) | Zhang, Xin (Daqing Oilfield Engineering Co., Ltd.)
ASP flooding using NaOH, alkylbenze sulfonate and HPAM has been put into industrial application at Daqing Fields. While significantly increasing oil recovery, it has also brought in new challenges for the handling of produced fluid such as precipitation of new mineral particles in the aqueous phase, scale deposition, foam, stable reverse emulsion in both produced fluid and produced water, and expanded rag layers in electrostatic treaters. To facilitate handling of the produced fluid and produced water by ASP flooding, numerous chemicals have been developed and applied, such as antifoams, demulsifiers, dual functional demulsifiers and reverse demulsifiers, sulfide scavengers, chelatants, and alkalines. A comprehensive scenario for the application of the above mentioned chemicals has been developed and applied in the handling of ASP flooding produced fluid at Daqing Fields. The scenario consists of continuous injection of dual functional demulsifier and reverse demulsifiers, antifoams at the inlet of production separators or into the produced water heated, recycled back to wellsites and blended into wellhead produced fluid to facilitate its flow to oil gathering stations, continuous injection of chelatant and alkaline into the produced water recycled back to be the wellheads, temporary injection of demulsifier and alkaline into the feed of bath heaters upstream of electrostatic treaters on an as-needed basis, batch injection of sulfide scavenger into the produced water recycled back to the wellheads, as well as batch injection of sulfide scavenger and alkaline into the feed or backwashing water of media filters treating produced water. The chemical treatment scenario has been successfully applied in 4 ASP projects using NaOH, alkylbenze sulfonate and HPAM at Daqing fields, significantly improving the performances of surface production facilities handling ASP flooding produced fluid.
Without regulation pertaining to the use and discharge of surfactant for offshore enhanced oil recovery (EOR) process in Malaysia, we adopted the guidelines from OSPAR (Oslo Paris Convention) that governs the use and discharge of offshore chemicals in the North Sea Region. In OSPAR, the CHARM (Chemical Hazard Assessment and Risk Management) model is being used to assess the risk of offshore chemicals to the marine environment. CHARM prescribes the Predicted Environment Concentration:Predicted No-Effect Concentration (PEC:PNEC) approach which ratio determines the hazard quotient (HQ) in order to rank the chemical by colour banding. Our surfactant formulation achieved a HQ of 2.16 or Silver colour banding with the stipulation that the volume of the discharged produced water is twice the volume of chemical solution (squeeze) injected. Nevertheless, in providing more certainty and confidence for both operators and local regulators to allow for overboard discharge of our flow-back surfactant formulation, we conducted a comprehensive produced water dilution modelling called DREAM (Dose-related Risk and Effect Assessment Model). The model calculates the Environmental Impact Factor (EIF) of each component of the chemical in the discharged produced water. Similar to CHARM, the DREAM uses the PEC:PNEC approach, but its PEC input parameters include environmental influences such as weather profile, current, etc. and incorporates a slick model. Its output is a quantation of the risks to the receiving environment, called the Environmental Impact Factor (EIF); where EIF is more than 1, the impact to the environment is significant. We simulated the chemical fate of individual component of the formulation with the scenario whereby the produced water is not treated prior to discharge. The time-averaged EIFs were more than 1 across all weather windows, indicating the discharge of untreated chemical-containing produced water is likely to have a localized environmental impact. We used both CHARM and DREAM as decision support tools for effective management of operational discharges from offshore projects. Limitations and recommendations from DREAM simulation results in the context of our EOR application are discussed.