The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems.
The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
In recent years, an industry-wide demand for increased drilling efficiency has led to the development of technologies and methods focused on multi-well pad development and the minimization of the transportation of drilling rigs between locations. Studies have indicated the potential for improving drilling cycle efficiency through improvements in rig design and procedural documentation but have given limited consideration to the unitization and mobilization practices surrounding ancillary components such as mud pumps, light plants, bulk fluid storage and other systems that comprise modern land rigs. This study examines current unitization practices, as well as offers alternative methods of integrating ancillary system components to improve current transport configurations. Specifically, ancillary systems whose transport dimensions and weight exceed the federal and state requirements for commercial vehicles operating within the National Highway Freight Network (NHFN).
In this study, the application of transport logistics software is used to demonstrate that there exists the potential for significant reduction in land rig mobilization costs through revised unitization of drilling rig ancillary systems. Permit data from proposed wells located in the Permian, Bakken, and Marcellus are utilized to develop transport scenarios whose focus is to quantify the impact of ancillary system unitization on the total fee structure associated with rig mobilization between geographical regions. Within each scenario, ancillary systems from currently active rigs are compiled and itemized according to their weight, transport dimensions, and degree of component unitization. The resulting schedule is then processed through transport logistics software to identify fee schedules associated with oversize permits, overweight permits, civilian and police escorts, driver rate/fuel costs, and associated service fees for the individual loads. Following the conclusions derived from the analysis of the existing rig systems, the series of transport scenarios are repeated using revised component configurations. The revised system employs a combination of divisible and non-divisible loads whose components are either integrated as part of dedicated transport trailers or located within ISO containers loaded onto commercially available transport trailers. The fee schedules from active rigs, as well as the results from the proposed unitization, are explored in detail to identify critical areas for improvement regarding unitization practices for active rigs and future builds.
Gupta, M K (Oil and Natural Gas Corporation Ltd.) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd.) | Singh, V K (Oil and Natural Gas Corporation Ltd.) | Bansal, R (Oil and Natural Gas Corporation Ltd.) | Pawar, A S (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.)
This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications.
A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations.
An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.
CML (Controlled Mud Level) is a dual gradient type of Managed Pressure Drilling (MPD). The CML system was developed and implemented on the Troll field to allow for reducing the annular pressures acting on the wellbore during drilling, thus allowing drilling areas weakened by faults and fractures and longer horizontal sections in the depleted normal pressured reservoirs. This paper will present a short introduction to the Troll field, a description of the system utilized, a summary of the rig integration, operations and experiences with the CML system on Troll.
Challenging drilling operations in the Vaca Muerta unconventional shale gas play have prompted operators to implement innovative drilling techniques to improve drillability and operational efficiency. Significant benefits have been reported by utilizing Managed Pressure Drilling (MPD), Underbalanced Drilling (UBD), and/or drilling with casing; however, challenges still exist, due to a variety of reasons. The heterogeneity found from field to field and within fields has resulted in wells with significant events, some resulting in loss of the well, even on the same pad where a previous well has been drilled uneventfully.
Arguably, the most successful non-conventional drilling technique being incrementally used in the area is MPD, often combined with UBD, particularly in gas wells. As with any new technology implementation, there is a learning curve which can be accelerated by translating learnings from successful experiences.
Three key components for a successful implementation on MPD are still building a collective experience in the Vaca Muerta play. Firstly, the equipment and associated technology is the key enabler for physically perform the operations safely and efficiently.
The second component is a ‘soft’ framework consisting of a robust layered approach including overarching standard policies, the MPD strategy for implementation in the specific project, conceptual and detailed procedures, and specific work instructions.
Lastly, the human component is a group of competent personnel, whom, at their specific responsibility level, understand the ‘soft’ framework, and knows how to operate the hardware to implement the technology so that objectives are met.
The potential of the technology is limited to the weakest of these three components. A strong combination of any two of them, not complemented by the third one, will most likely result in a partial success at best, if not a complete failure at worst.
The operator had recently three major events in wells being drilled with MPD, which resulted in the loss of the wells. After implementing a training program on MPD/UBD, which emphasized the human factor and understanding of the equipment, the ‘soft’ framework of strategy, procedures and project management, the safety and efficiency during operations has increased significantly. This resulted in a better handling of events related to bottom hole pressure control without a single well loss event to the date of writing this document, approximately nine months of continuous operations. The other mainstay of this process has been the flexibility to adapt the application of the methodology based on the well challenges encountered.
Sengupta, Partha (Oil and Natural Gas Corporation Limited) | Katre, Narendra (Oil and Natural Gas Corporation Limited) | Suman, Abhinav (Oil and Natural Gas Corporation Limited) | Das, Barnali (Oil and Natural Gas Corporation Limited) | Pawar, Anil (Oil and Natural Gas Corporation Limited) | Deshpande, Sunil (Oil and Natural Gas Corporation Limited)
In any onshore gas installation, bath-heaters and high pressure separators are provided as standard surface facilities to take production from high pressure wells having hydrate forming tendency. Medium pressure separators are also provided to take production from medium pressure gas wells. The paper deliberates on an optimized surface installation for handling high pressure well fluids with possibilities of hydrate formation. The study has been carried out through steady state multiphase simulation considering pressure & production profile of the wells, consumer requirement and flow assurance i.e. hydrate formation. An optimized process scheme and production strategy is presented for early production from both high pressure and medium pressure gas wells in a single separator and without any bath heater.
Based on well test data, well completion data and pressure profile, simulation studies are carried out in steady-state multiphase flow simulation software to look into possibility of hydrate formation in the flow lines or in process piping. Flow from wells having high well-head pressures in the range of 120 to 165 kg/cm2g (ksc) are simulated by varying the separator pressure, flow line size & length and choke arrangement. Flow simulations are carried out for different choke combinations and flow line arrangements to keep well fluid temperature above hydrate formation temperature in the entire flow path from well head to separators.
It was established from simulations that flow from the well having highest production as well as highest well head pressure of 165 ksc can be taken by operating the separator at 33 ksc and adopting a multi-choke arrangement along the flow line without any possibility of hydrate formation in the system. The multi-choke arrangement consists of putting chokes including well head choke at well site, at installation inlet and the final choke at installation inlet manifold. The arrangement also envisages additional small length of flow line as buried portion near installation inlet to take advantage of heat gain from soil. From 2nd year onwards of the profile period, it is observed that with reduction in well head pressure to 132 ksc as per profile, the well can be produced by operating the separator at lower pressure without any hydrate formation. For rest of the wells, only multi-choke arrangement is found to be sufficient to prevent hydrate problem while operating the separator at even lower pressure throughout the profile period. It is also observed that higher production can be taken from the wells from 2nd year onwards on account of operating the separator at lower pressure.
The optimized scheme has marked deviation from the earlier proposed standard scheme with substantial reduction in number of equipment and consequent reduction in CAPEX & OPEX. This novel process scheme and production strategy eliminate the need for investment in both high pressure separator and hydrate mitigation measures like heat tracing, methanol injection or bath-heaters. This innovative production strategy also facilitates better recovery from the gas wells on account of operating the separator at lower pressure.
Managing adequately pressure drawdown should be a key technical reservoir management driver due to its major impact on cash flow, acceleration and final recovery factor for operating hydraulically fracture shale gas condensate producers. Permeability should be regarded as a key dynamic property for ultra-low permeability shale reservoirs that influences shale hydrocarbon recovery. It is paramount to develop a pressure depletion plan that captures the pressure drawdown strategy and the changes in flow capacity associated to the interaction of the nano-Darcy rock and hydraulic fractures with stress dependent permeability effects.
Defining the adequate drawdown strategy would aid maximizing the economic recovery. Considering the variability of permeability with pressure drawdown should be part of the reservoir management lifecycle for unconventional shale reservoirs. This study focus on evaluating the impact of pressure drawdown strategy on initial rates and recovery for a Duvernay Gas condensate producer with an initial condensate yield of 100-150 stb/mmscf.
A sector compositional reservoir simulation model was built for a horizontal multistage hydraulically fracture Duvernay shale gas condensate producer. A full assessment of variability of permeability in the nano-Darcy rock and in the propped hydraulic fracture stages near the wellbore region was accomplished. Aggressive, moderate and conservative pressure drawdown strategies were evaluated, considering multiple operational pressure drawdown incremental ranges from 14.5 to 95 psia per day.
Results clearly indicate that implementing daily pressure drawdown increments of 22 to 29 psia per day would provide a similar recovery factor than imposing daily pressure drawdowns of 44 to 95 psia per day. However, there is a golden operating window opportunity to accelerate recovery by imposing maximum drawdown from the early days of production and bringing significant benefits of accelerating recovery with an associate increase in revenue but the benefits of this acceleration vanished in less than one year due to substantial changes in hydraulic fracture conductivity and also in the nano-Darcy rock permeability in the near wellbore region. The reduction of nano-Darcy permeability is a function of pressure, time and distance from the hydraulic fractures. According to our results, the best reservoir management practice for operating lean/medium Gas Condensate unconventional shale producers should be maximizing pressure drawdown at the early stage of the life cycle and deferring the installation of production string to maximize inflow-outflow.
The performance of a new synergistic biocide combination based on glutaraldehyde and THNM (tris (hydroxymethyl) nitromethane) was extensively evaluated in laboratory trials using water samples from twenty-six Brazilian and Argentinian oilfields. The performance was ultimately validated in four field trials, two per country (A1, A2, B1, B2), over a three month duration.
For laboratory tests, water samples were collected from numerous locations of the various oilfields and characterized/enumerated by serial dilution (SRB and APB bug bottles), ATP, and molecular biology techniques (NGS). Water and isolated indigenous SRB/APB from the most contaminated locations were used as the matrix and test inoculum for the biocide optimization tests. Numerous biocide systems, at total active ingredient concentrations ranging from 111 to 250 ppm, were evaluated by assessing the ability to rapidly kill the native organisms (2 hour contact time at room temperature) and protect the water from contamination over a prolonged time frame (≥7 days) under heat-aged conditions (60°C). Results demonstrated that glutaraldehyde/THNM provided the best performance in the majority of the samples evaluated and was therefore selected for performance evaluations in field tests owing to the enhanced performance of this particular treatment in the laboratory.
Field trials were conducted by applying the lowest total biocide concentration that demonstrated a ≥ 4 log10 microbial reduction (in the laboratory studies) at various problematic field locations. All biocides were dosed as batch treatments 2-3 times per week (2-3 hours per treatment). Specifically, the co-dosed glutaraldehyde/THNM combination replaced incumbent treatments of either THPS or glutaraldehyde (batch dosed) in combination with a quaternary ammonium compound which was being applied by continuous injection:
Furthermore, in the B1 and A1 trials, NGS results indicated a shift of the microbial population to less harmful (non-MIC relevant) organisms. Overall, the novelty of this biocide combination is its ability to provide strong, broad-spectrum antimicrobial performance and long-term effectiveness, as compared to traditional biocide chemistries.
Two new Non-Intrusive Reduced Order Modelling approaches to estimate time varying, spatial distributions of variables from arbitrary unseen inputs are introduced. One is a generalization of an existing'dynamic' approach which requires multiple surrogate evaluations to model the solutions at different time instances, the other is a'steady-state' approach that evaluates all time instances simultaneously, reducing the local approximation error. The ability of these approaches to estimate the water saturation distributions expected during a gas flood through a 2D, dipping reservoir is investigating for a range of unseen input parameters. The range of these parameters has been chosen so that a range of flow regimes will occur, from a gravity tongue to a viscous dominated Buckley-Leverett displacement. A number of practically relevant model error measures were employed as opposed to the standard L2 (Euclidean) norm. The influence of the number and the structure of training simulations for the model was also investigated, by employing two simple experimental design methods. The results show that POD based NIROM approaches are prone to significant deviations from the true model. The main sources of error are due to the non-smooth variation of system responses in hyperspace and the transient nature of the flows as well as the underlying dimensionality reduction. Since the first two sources are properties of the physical system modelled it may be expected that similar problems are likely to arise independently of the interpolation method and the reduction process used.
Hassan, Amjed (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Majed, Abdulaziz (King Fahd University of Petroleum & Minerals) | Al-Nakhli, Ayman (Saudi Aramco) | BaTaweel, Mohammed (Saudi Aramco) | Elktatany, Salaheldin (King Fahd University of Petroleum & Minerals)
Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution for condensate removal in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. Also, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal.
In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in-situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature, or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 hrs. of mixing and injection. Also, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used.
The results of this study showed that, the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure from the thermochemical reaction. These micro-fractures reduced the capillary forces that hold the condensate and enhanced its relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.