Pathak, Shashank (Cairn Oil & Gas, Vedanta Ltd.) | Ranjan, Ashish (Cairn Oil & Gas, Vedanta Ltd.) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd.) | Vermani, Sanjeev (Cairn Oil & Gas, Vedanta Ltd.) | Tiwari, Shobhit (Cairn Oil & Gas, Vedanta Ltd.) | Shrivastava, Pranay (Cairn Oil & Gas, Vedanta Ltd.) | Nagar, Ankesh (Cairn Oil & Gas, Vedanta Ltd.) | Ahsan, Mohammad Ayaz (Cairn Oil & Gas, Vedanta Ltd.) | Modi, Jaya Kumari (Cairn Oil & Gas, Vedanta Ltd.) | Upadhyay, Akhilesh (Cairn Oil & Gas, Vedanta Ltd.)
Mangala, Bhagyam & Aishwaraya Oil fields with ~669 wells produce about 20% of India's domestic crude production. As a part of production enhancement & sustenance activity various stimulation treatments were implemented from the initial development phase of these fields. Over time as these fields went from water flood to polymer flood, several modifications were made in stimulation treatment design to maintain the effectiveness of the stimulation treatments. Over last 8 years over 1100 stimulation treatment were executed in these field with most of the information kept within the treatment specific reports. To tap the value from this huge volume of information, a data structure was prepared to extract important learnings from these treatments. This paper details the workflow which was adopted to compile the historical unstructured data in a structure and details the crucial findings & learnings from the advanced data analytics applied on this data.
The primary objective of this work was to put unstructured data from 1100 stimulation treatment into a structured format. Information specific to the treatment design such as treatment fluid, volumes, concentrations, additives, pumping technique, soaking time etc. were compiled. This was also followed with wells specific information such as completion details, formation type, pre and post stimulation production/injection rates etc. Since the information volume was large and the data was scattered, a stimulation job code was defined which carried all the relevant information about any stimulation treatment in a simpler, scalable and structured format. The work was followed with advanced data analytics to extract value from this historical data spread over last 8 years. Stimulation performance indexes were defined to evaluate effectiveness of all these treatments which helped to identify root causes which led to some of the most successful stimulation treatments and helped to delineate learnings from unfavorable results.
The work identified the primary factors impacting the performance of stimulation treatments from broad field level to well & formation specific learnings. The overall findings included job specific learnings, findings specific to treatments fluid such as composition of chelating agent and its impact, concentration of HCl on injection improvement etc. as well as operational aspects while executing these jobs.
There are numerous technical papers on effectiveness on stimulation treatments and their design, this paper compiles the learnings from over 1100 stimulation treatments which provides a bridge between the theory and the practice while it also provides crucial insights on the operational aspects of these treatment as well which can impact the performance of these treatments. The paper also details the novel workflow adopted to structure the unstructured historical data to create substantial value.
Mohd Nazri, Asraf (Petronas Carigali Iraq Holding B.V.) | Yahaya, Fadzil (Petronas Carigali Iraq Holding B.V.) | Musa, M Nizar (Petronas Carigali Iraq Holding B.V.) | Salleh, Zaimi (Petronas Carigali Iraq Holding B.V.) | Jasmani, Mohd Shahrizal (Petronas Carigali Iraq Holding B.V.) | Abit, Anwar (Petronas Carigali Iraq Holding B.V.) | Aman Shah, Muhammad Kamal (Petronas Carigali Iraq Holding B.V.) | Kamaludeen, Mohd Ali (Petronas Carigali Iraq Holding B.V.)
PETRONAS Carigali Iraq BV (PCIHBV) is the Operator for an onshore oil field which is located in a 30 km x 10 km Contract Area at the southern part of the Republic of Iraq. One of the key activities undertaken by PCIHBV during the development and production campaign is well intervention which involves acid stimulation, well clean up and unloading of newly drilled wells. The conventional practice in Iraq for acid stimulation and well clean-up operation for carbonate reservoir is to burn the recovered hydrocarbon at dedicated flare pit area. This is normally followed by Multi Rate Test (MRT), which takes up to 10 hours of continuous flaring operation for each perforated zone.
Some of the critical challenges posed by the above approach include managing and ensuring safe operation for personnel working in this rig-less operation. The flaring activity would release unburned oil, gas fumes, noise, heat and black smoke to the environment. Moreover, there had always been interruptions from the nearby communities who were affected by the release of fumes and smokes from the flaring activi ty which had adversely impacted their health and the surroundings. This situation had regrettably resulted in hostile protests by the affected villagers which could be a threat PCIHBV operations. A technical assessment was conducted to devise a safer, secure and environmentally friendly approach to replace the conventional flaring method. At the same time, PCIHBV also envisioned to minimize the duration required from flaring activities.
A new approach called "Zero Flaring" was introduced. The concept of Zero Flaring is meant to treat and neutralize the recovered crude during well clean up and divert the flow towards oil processing facilities. This will then rule out the need to burn the recovered crude in the flare pit. To implement the ‘Zero Flaring" only a minimal site modifications were required with few additional equipment such as chemical injection skid, tanks, sampling points and associated connection. This method has totally eliminated the need for flaring while safeguarding the asset integrity of the processing facilities. This innovative approach has been acknowledged by the Host Authority as it has resolved the flaring issues with minimal expenditures required. As of March 2019, PCIHBV has conducted new wells unloading using "Zero Flaring" method in more than 10 wells. PCIHBV is committed to further improve the ‘Zero Flaring’ method to reap its benefits.
This new method has showcased PCIHBV's commitment, values and capabilities as a prudent Operator to safely and timely deliver the production targets without neglecting the social wellbeing of the surrounding communities, the protection of the environment and the integrity of the asset. Above all, it has strengthened PCIHBV's presence in this region and further enhanced our reputation as an International Oil Company (IOC) of choice.
In recent years, in unconventional reservoirs, main fracture parameters including fracture permeability and fracture volume can be early evaluated using flowback data analysis. For analysis purposes, diagnostic plots, straight-line methods, and simulation model history-matching techniques are utilized. Usually, immediate gas and water production occur during flowback in shale gas wells. In this paper, solution of water diffusivity equation for different flow regimes during the early time of well life was used to analyze water performance. These flow regimes were determined based on the diagnostic plot of water rate vs. time. The analysis from Water RTA was used to calculate initial water in place (OWIP) and fracture parameters. The difference between the OWIP and the injected fracturing fluid was correlated against the formation water saturation. The main conclusions from this analysis are; 1) High quality shale if the OWIP equal to the total injected water volume, and water-production data usually do not show the transient period and in some cases, boundary dominated flow (BDF) is present.
Well testing equipment for unconventional onshore applications generally comprises a sand removal unit (Desander), a dual choke manifold, a test separator with metering, various types of tanks for temporary storage and in some cases a flare. This equipment is typically interconnected through high pressure temporary flowline generally referred to as flow-iron, which is made up from modular components that are joined by quick connect hammer unions. Installation of the equipment and the well testing itself is labor intensive. Personnel is on location 24 hours a day, working on or near high pressure piping and climbing onto open top tanks during well testing.
Li, Jun (China University of Petroleum-Beijing) | Liu, Yuetian (China University of Petroleum-Beijing) | Xue, Liang (China University of Petroleum-Beijing) | Cheng, Ziyan (China Petroleum & Chemical Corp SINOPEC) | Kong, Xiangming (China University of Petroleum-Beijing) | Li, Songqi (China University of Petroleum-Beijing)
After fracture treatment in unconventional reservoirs, the in-situ stress and fluid pressure are greatly changed in the reservoir because of the generation of fracture networks. In order to get high production, efforts are made to get close fracture spacing and long fracture length in-situ field, which in turn make fracture distribution become complicated as the range of fractures size and density is widespread.
In this work, the finite element method is used to analysis flowback around hydraulic fracture among complex fractures networks, which consider the coupled effects of flow and geomechanics.
The reservoir is assumed to be a 3-D poroelastic medium. According to the fracture sizes, the fracture is divided into three types. These small natural fractures are treated as SRV regions, hydraulic fractures, natural fracture in middle and large sizes are explicitly represented using LGR. Finite element method simulates fracture deformation and the two-phase fluid flow in the reservoir during flowback stage. The physical properties are altered by the coupled flow and geomechanics in the reservoir.
The fluid pressure, stress and flowback production over time around these fractures are recorded. The results show that during the flowback period, the production experience a sharp decrease. The porosity and permeability in the reservoir are greatly reduced because of the coupled effects. These explicit natural fractures influence the hydraulic fractures. As the hydraulic fracture spacing reduced, the stress shadow effects become more serious and the flowback production decreases.
This work helps understand the flowback analysis with coupled geomechanics and flow effects in the complex fracture networks in the unconventional reservoirs and physical properties effects in different reservoir conditions.
Since 1st February 2019 Total E&P UAE Unconventional Gas B.V started to operate the Diyab shale gas field in which three horizontal exploration wells had been drilled by ADNOC. Mult- stage hydraulic fracturing treatments were performed on these wells followed by long term well testing to assess the formation potential for a further development.
It was a challenging project since it was the first shale gas frac campaign in UAE where the unconventional reservoir developments are at beginning phase. Various operational problems emerged in wireline pump down, coiled tubing milling and H2S treatment operations, especially during execution in the first well. These operational issues were mainly related to equipment availability and compatibility, personnel competency, logistics support and societal concerns of environment. Corrective measures and innovative designs were conducted to solve the technical issues and improve the operation performance. Good learning curves of different operations were achieved from the first well to the third one.
The lessons learned from this hydraulic fracturing campaign are valuable experience that will be applied to the future pilot wells in Diyab field for the continuous optimization.
Modelling fracture systems where fracture mechanics and fluid flow are consistent, constitutes an essential part for predicting the performance of shale oil and gas operations. One of the challenges in these complex systems is the reconciliation of volumes of injected water during fracturing, hydraulic fracture volume and the water flowback after the well is open to production. Achieving consistency becomes even more challenging given the interdependence of multiple sources of uncertainty.
We propose a workflow that uses multiple sources of observed operational data, such as volume of water injected and produced, static pressure, soaking time and saturation logs, to calibrate a static model representing the fracture volume and rates of water imbibed into the matrix. The soaking period is modeled using Embedded Discrete Fracture Model (EDFM) that honors the fracture geometry generated by a commercial software based on unconventional fracture model (UFM). The allocation of water imbibed into the matrix during the soaking period uses imbibition capillary pressure from 3D numerical models.
After applying the proposed methodology to calibrate stimulated shale oil reservoir in a multi well pad, we can assess the relative impact of fracture complexity compared to capillary dominated flow. Additionally, we can perform sensitivities on impact of the water retained in the fracture volume and matrix, respectively. Finally, the methodology showed that we can use the imbibition capillarity to explain and reconcile water losses during the soaking period. This information is of key importance while deciding the value of the flowback rates as input during calibration of hydraulic fracture area and quality of the stimulation procedure. Extended applications of this workflow include performance assessment of gas entrapment and evaluation of EOR operations in unconventional systems.
We propose a methodology based on the hypothesis of capillary imbibition mechanism to explain and capture the volume of injected water that does not return during hydrocarbon production. This workflow, well suited for realistic complex Hydraulic Fracture Networks (HFNs) consisting of millions of fractures planes, enables calibration of fracturing fluids and water flowback while assessing the effect of the spontaneous imbibition.
Low injected fracturing fluid recovery has been an issue during flowback period that is highly impacted by the fracture closure behavior. Although existing flowback models consider fracture closure volumetrically, they do not represent the true situation of non-uniform fracture closure. In this paper, we proposed a coupled geomechanics and fluid flow model for early-time flowback in shale oil reservoirs. The fluid flow model is coupled with an elastic fracture closure model through finite element methods. In this study, three stages are modeled: fracture propagation, well shut-in and flowback. Cohesive Zone Method (CZM) has been used for modeling fracture propagation. The presented model distinguished the propped part from the unpropped part of the fracture. At the beginning of flowback, the proppants may not be completely compacted in early shut-in time. Thus, permeability evolution during closure is tracked using a smooth permeability transition function. The numerical results have shown that fracture closure during the flowback period is often not uniform. While the uniform fracture closure leads to maximum fracturing fluid recovery, an aggressive pressure drawdown strategy may damage fracture connectivity to the wellbore. An integrated flowback model enables modelling nonuniform fracture closure in a complex fracture network. This study highlights that by choke/pressure drawdown management, operators can influence fluid recovery and even maintain high fracture conductivity. Furthermore, the methodology presented in the paper can also be used for inverse analysis on early flowback data.
Quintero, Harvey (ChemTerra Innovation) | Abedini, Ali (Interface Fluidics Limited) | Mattucci, Mike (ChemTerra Innovation) | O’Neil, Bill (ChemTerra Innovation) | Wust, Raphael (AGAT Laboratories) | Hawkes, Robert (Trican Well Service LTD) | De Hass, Thomas (Interface Fluidics Limited) | Toor, Am (Interface Fluidics Limited)
For optimizing and enhancing hydrocarbon recovery from unconventional plays, the technological race is currently focused on development and production of state-of-the-art surfactants that reduce interfacial tension to mitigate obstructive capillary forces and thus increase the relative permeability to hydrocarbon (
A heterogeneous dual-porosity dual-permeability microfluidic chip was designed and developed with pore geometries representing shale formations. This micro-chip simulated Wolfcamp shale with two distinct regions: (i) a high-permeability fracture zone (20 µm pore size) interconnected to (ii) a low-permeability nano-network zone (100 nm size). The fluorescent microscopy technique was applied to visualize and quantify the performance of different flowback enhancers during injection and flowback processes.
This study highlights results from the nanofluidic analysis performed on Wolfcamp Formation rock specimens using a microreservoir-on-a-chip, which showed the benefits of the multi-functionalized surfactant (MFS) in terms of enhancing oil/condensate production. Test results obtained at a simulated reservoir temperature of 113°F (45°C) and a testing pressure of 2,176 psi (15 MPa) showed a significant improvement in relative permeability to hydrocarbon (
Measurements using a high-resolution spinning drop tensiometer showed a 40-fold reduction in interfacial tension when the stimulation fluid containing MFS was tested against Wolfcamp crude at 113°F (45°C). Also, MFS outperformed other premium surfactants in Amott spontaneous imbibition analysis when tested with Wolfcamp core samples.
This work used a nanofluidic model that appropriately reflected the inherent nanoconfinement of shale/tight formation to resolve the flowback process in hydraulic fracturing, and it is the first of its kind to visualize the mechanism behind this process at nanoscale. This platform also demonstrated a cost-effective alternative to coreflood testing for evaluating the effect of chemical additives on the flowback process. Conventional lab and field data were correlated with the nanofluidic analysis.
Experience has shown that hydraulic fracturing operations can introduce and/or stimulate microbial populations in the wellbore that in turn may lead to undesired corrosion, souring or other production issues. Biocides are applied to prevent the establishment of problematic microbes. Characterizing and quantifying which microbes will be introduced to a well using molecular techniques allows for optimized or even proactive treatment and prevention strategies to be implemented, whereas, traditional microbial testing methods have proven insufficient.
Once the standard for microbial assessments in the oil and gas industry, culture media bottles are now just one of many available tests. Tests vary by their resolution (culturable, active and living, total microbes), and the information they yield. Some tests target very specific microbial subgroups of concern (culture media, qPCR), while others evaluate all microbes within the sample (ATP, qPCR, 16S rRNA sequencing). In the case studies presented, water and produced fluids were collected from all pertinent frac sample points (source waters, pre- and post-chem and post completions) and were assessed using the suite of microbial methods stated above.
Three case studies are presented with several noteworthy observations regarding the value microbial tests provide to frac operations. First, culture media-based testing consistently resulted in incoherent and confusing data that failed to correlate with the remaining testing technologies. Second, ATP technology provided efficient and timely testing which lent itself well to on-site, evidence-based decision making. During one of the fracs, ATP results were used to modify and optimize a microbial control program on-the-fly. Third, DNA-based testing (qPCR and 16S rRNA sequencing) provided the most comprehensive insight into the microbial communities exposed to the well, and those that established post-completions.
Overall, holistic microbial testing offers the user key information required to design and implement successful microbial control programs for frac. Without it, microbial issues plagued production efforts. Culture media tests provided limited and unreliable information and were deemed not suitable for frac operations. ATP provided a useful microbial load in real-time but could not elucidate the types of microbes present. DNA testing filled this gap by providing quantities and types of microbes present.
Apart from assessing microbial control programs during the frac, monitoring the production fluids is essential to assuring continued well performance. The acknowledgment of the role microbes play in well completions, and the testing technology to evaluate oilfield microbes is rapidly advancing. Here we present some of the first case studies highlighting the use of molecular, DNA-based technology for assessing hydraulic fracturing operations and showing the fallacy of culture media-based testing which is the current industry standard.