Organizations today, especially in the oil and gas sector, are swimming in data  but most of them manage to analyze only a fraction of what they collect. To help build a stronger data-driven culture, many organizations, starting with technology companies, are adopting a new approach called self-service analytics. In this paper, we present our big data and analytics architecture that has enabled our in-house and outsourced engineering, and data science teams, to develop self-serving AI models and data pipelines. Our architecture is presented to the reader in such a way that he/she can apply it using the cloud provider of their choice by translating the concepts presented here, either to native cloud PaaS or using open source products.
This paper was written with the main propose to share the experience of more than ten years of cyclic steam stimulation (CSS) in a heavy oil field with a big amount of challenges such as low injectivity, sanding, steam channeling, low steam efficiency, among others.
For each item identified with a high impact on the CSS production and efficiency, a methodology to analyses and optimization was developed. the first step is identifying the item, recollect the information and quantify the impact; after that, the information is analyzed by the reservoir team, some solution is suggested and evaluated by numerical simulation and other tools; then, the best solution found is apply like a pilot on the field and according to the results it is implemented in a full field scale or replanting until to get the hope results. Finally, corrective actions are taken to avoid similar troubles in the future development of the field. Lesson learners are divulged to the members of the organization.
For the case of low injectivity, this was identifying in the first stage of development of the field; we carried on lab cores to found the presence of swelling shales like the main causes. Inhibitors clays were test on lab and implemented in the first cycles; for the next steps of development we acquired steam generators with a high-pressure setting too. On the other hand, steam channeling was identified in wells with more of five cycles of stimulation; others wells with potential channeling was identified too, and a methodology to inject this kind of wells was development with the help of simulation tools and successfully implemented in field. The injection of other fluids with the steam like nitrogen, foam or gels improved the low steam efficiency; the development methodology is included in the paper.
This papers include a lot of experiences in the improving of cyclic steam stimulation, test lab, numerical simulation and other tools are combined with the field experience obtaining an improve in the oil production. Real data field, CSS information and developed methodologies are included in the paper. For this reason, this paper is useful to future implementation of CSS process and in other fields with similar features.
Mogollon, M. (Frontera Energy) | Arguelles, A. (Frontera Energy) | Rodriguez, A. (Frontera Energy) | Anaya, O. (Ecopetrol) | Miranda, S. (Schlumberger) | Velasquez, E. (Schlumberger) | Villalobos, J. (Schlumberger)
Electric submersible pump (ESP) applications with heavy oil pose substantial technical challenges: decreased pump head capacity, increased power requirements, and poor cooling capacity. This paper shares experiences, lessons learned, equipment standardization exercises, and improvements performed in a field with heavy oil (13º API to 15ºAPI) to extend mean time between failures (MTBF) in more than 3,000 days in a high ESP population with an average of 500 wells. To achieve production goals and extend ESP run life, the project tracks five elements of the ESP life cycle: design, optimization, failure analysis, monitoring, and equipment standardization. As the field evolved, ESPs faced the challenges such as: increased production with increasing water cuts to higher flow rates in horizontal completions with high dogleg severity. Chronological performance of pump mean time between failure is shown before and after improvements. The ESP lifecycle is used as the basis to analyze several factors that caused either total system failure or inability to meet production expectations. This paper explains the implications of each factor and how they affect ESP components, through case studies of representative or repetitive failures and examples of how they were remediating without incurring the expense of oversizing the ESP equipment or completion. This paper shares lessons learned in a five-year, dynamic heavy oil project and includes practical tools to improve ESP run life and optimize well production, which are applicable across the industry and around the world.
Gheneim, Thaer (Schlumberger) | Azancot, Annalyn (Schlumberger) | Acosta, Tito (Ecopetrol) | Zapata, Jose Francisco (Ecopetrol) | Chaparro, Carlos (Ecopetrol) | Lobo, Adriano (Ecopetrol) | Jimenez, Ana María (Ecopetrol) | Perez, Gerson (Ecopetrol)
Casabe field reservoir characteristics are multilayer, geological complexity, vertical/areal heterogeneity and commingled production. Due large difference in mobility between oil and water (M ~ 20) and the maturity of water flooding, several operational problems have arisen, such as, increase of water cut, channeling, sand production, etc. These problems together with the high remaining reserves and identification of bypassed oil, were the main reasons to evaluate EOR process as a solution to increase the recovery factor.
A reduced Cycle Time was created to reduce the time from design to full field implementation which involves the following phases: Screening/Conceptual Design, Pilot Design, Drilling-Workover and Facilities, Operation & Surveillance, Pilot Expansion, Full Field Development Plan, Reserves & FID. This strategy is based on multitask parallel process to allow fast track decision making and activities execution for a fast pilot implementation, which allowed to implement the EOR pilot in 24 months form the screening to pilot Operation & Surveillance. After the screening, polymer flooding was considered for mobility ratio modification to improve sweep efficiency and therefore increase RF.
The best producer layers were selected, based on the areal continuity and residual oil in place, as target sands for polymer injection. One pattern was selected for the pilot. Laboratory tests, along with reservoir simulation confirmed the potential of chemical EOR in the selected sands and pilot area. Polymer injection was performed in four injector wells of the selected pattern. The polymer flooding process was monitored in the central producer and in the eight producers of the second line.
A surveillance plan was implemented to collect the information required to evaluate, with the lowest uncertainty, the results of this pilot. An observation well was drilled to monitored changes in oil saturation. The surveillance plan was critical to be able to control the polymer injection process, to have a proper technical evaluation of the pilot and to optimize costs during the future expansion and full field implementation. Polymer flooding have increased the RF on the selected area.
The fast-tracking strategy for an EOR project execution was successfully implemented in Casabe Field and the pilot was delivered in 2 years proving the concept of 5-year road map it is possible. The reduced Cycle Time (5-year Road Map) could be used as reference for implementation of new EOR pilots in other fields in shorter time and optimizing resources.
The workflows used and the analysis procedures created for this pilot could be used as reference for the implementation of future pilots in fields with similar characteristics.
Bahamon, Cristhian C. Tello (Schlumberger) | Hill, Carlos Reyes (Schlumberger) | Sanita, Carlos (Schlumberger) | Artola, Ricardo (Schlumberger) | Lapania, Fernando (Schlumberger) | Doval, Jorge (Ecopetrol)
The development plan of Casabe field defined the drilling of producer wells with "S type" deviation geometry and cased hole completion with progressive cavity pump (PCP) systems because this plan offers the greatest advantages in wells with solids production. However, this combination creates an environment for repetitive failures due to severe friction between rod string and production tubing. A group of 40 wells with PCP was identified;these wells had three or more interventions per year. An extensive root cause analysis concluded that 44% of failures in wells with PCP were directly linked to tubing and rod wear, especially in highly deviated wells and high operating revoluetions per minute (RPM). With the aim to increase the run life and decrease the intervention index of producer wells, a pilot test of new technologies such as the electric submersible PCP (ESPCP) were proposed; an ESPCP isa bottom-drive PCP that eliminates the rod string while maintaining the advantages of solids handling.
Devia, Néstor (Baker Hughes) | Aguinaga, Pilar (Baker Hughes) | Gonzalez, Camilo (Baker Hughes) | Reina, John (Ecopetrol) | Gil, Layonel (Ecopetrol) | Bonilla, Fernando (Ecopetrol) | Niño, Luzmila (Ecopetrol)
Maximize oil production at the lowest cost, reduce the process facilities used for secondary recovery water injection projects and increase the static pressure of mature reservoirs was a need in Chichimene Field due to the challenging oil market conditions and the declining oil production rates. The legacy solution used by Ecopetrol consisted in producing water with artificial lift and then re-injecting it through horizontal pumping systems. This water injection method did not maximize oil recovery with the available resources.
Ecopetrol and Baker Hughes implemented the Dumpflood completion with electrical submersible pumping to address the challenges encountered in Chichimene field. The Dumpflood completion is a closed loop concept where water is produced and injected in a single well avoiding surface processes. This implementation allowed Ecopetrol to develop secondary oil recovery in a simplified and cost effective completion.
This paper will present the results of the first pilot of Dumpflood completion in Chichimene Field in Colombia. This Promoted enhanced oil recovery in the target injection zones, in addition, significant savings in capital expenditures were obtained due to the reduction of surface production tubing and required licenses for the oil industry in Colombia. Operating expenditures such as maintenance, water treatment, and energy costs were also reduced.
The success of the Dumpflood completion with electrical submersible pumping permitted the initiation of a change in the legacy water injection method in Chichimene field. It was demonstrated that the oil market is continuously in need of innovative completions solutions to optimize resources and oil recovery.
SUMMARY: Directional drilling in fields bedding plane formations has become a challenge to the petroleum industry because of the complexity of its operations. Therefore, drilling geomechanics plays an important role in engineering planning and calculation prior to the construction of a wellbore which makes it possible to determine a possible instability of the rock formation associated to the drilling inclination of wellbore and inclination of preexisting bedding plane. This paper analyzes the effect of the attack of angle of drilling on the geomechanical wellbore stability of formations with weak bedding plane or laminations using a finite element model and the Abaqus® software considering the rock as an isotropic medium. Three analytic tests with different drilling angles were developed, allowing to establish relationship between the attack angle and wellbore stability. Variables such stress, deformation and failure in rock bedding plane during drilling were analyzed. The results show that at higher attack angles the greater the wellbore instability is associated with the presence of the weak bedding plane
During the drilling of hydrocarbon wells various types of rock and lithologic formations are drilled, including among them naturally laminated ones or bedding planes formations. These formations contain natural disorders that are called weak bedding plane, which represent a major operational challenge during drilling due to the characteristics of its surfaces with little or no cohesion between them. This causes a displacement and imminent separation of the surfaces, namely, unstable conditions when being altered mechanically with the cutting bit, generating slides and cavings into the wellbore which subsequently cause operational problems during drilling such as stuck pipe or loss of circulation causing extra costs in wellbore drilling. It is of the utmost importance to analyze the intensity of the instability of the wellbore depending on the direction and angle with which the weak bedding plane are perforated.
Medina, Leonardo Arias (Universidad de America, Bogota) | Lozano, Henry Andrey (Universidad de America, Bogota) | Mantilla, Hernan Dario (Ecopetrol) | Espinosa Mora, Carlos Alberto (Universidad de America, Bogota)
SUMMARY: After the success of the drilling campaigns in unconventional shale reservoir in the United States, Ecopetrol wanted to replicate their success in Colombia as well. During the past years a drilling campaign encountered several unique issues for shale plays in Colombia. With the advances in electrical logging, petrophysics, geomechanical and geochemical analyses allowed understanding the shale plays in a basin in Colombia.
Geomechanics has been useful in providing the required information for the design of optimal well trajectories for efficient development of unconventional reservoirs. Additionally, extensive tri-axial and total carbon organic (TOC) tests in shales have been included in the study to calibrate the mechanical properties and TOC obtained from the electrical logs. The concept of critically stressed fractures has been included in the analysis of this geomechanical model in order to know the conductivity of the natural fractures in shale plays.
The present study displays a methodology for the design of a mud weight window as well as a geochemical analysis for the sweet spot selection in the shale plays. The geomechanical model considers transversal vertical anisotropy (TIV) with the use of Stoneley wave from sonic scanner tool necessary for the determination of the anisotropic mechanical properties and in-situ principal stresses. The present study includes conclusions and recommendations for unconventional shale reservoirs in Colombia.
1 INTRODUCTIONOil companies have always wanted to drill wells in unconventional fields, but because of their complexity and limited technology in the time were an impediment.
SUMMARY: This work presents a methodology for mud losses mechanism evaluation based on geomechanics of fractures. Several and catastrophic mud losses events are continuously experienced during drilling the 8½¨section in Castilla Field in Llanos basin, Colombia. Technologies like Manage Pressure Drilling (MPD), thixotropic fluids, LCM (Lost Control Materials), ECD (equivalent circulating density) management were applied to avoid/manage mud losses but the issues associated to mud losses continue being a major problem causing among others wellbore instability in K1 superior formation due to fluid static column variations. According to the events, wellbore instability becomes the new problem causing hole cleaning issues, tight hole and restrictions tripping drill pipe and 7¨ liner. In image logs were detected several natural fractures both open and partially open. Fracture´s hydraulic conductivity hypothesis was proposed. To better understand the problem an evaluation of critically stressed fracture analysis was conducted by estimation of normal and shear stresses in each fracture plane assuming pressure transmission from the wellbore to the fractures. Geomechanical parameters estimated for each interval in which fractures were identified, entered the analysis as an input. Then, the fracture´s stresses were compared to the rock´s failure envelope assuming no cohesion in the planes. As a result, was figure out a reactivation gradient, which is compared to the pressure losses estimated based on the static column height in wells that experienced mud losses. The main observation is that there exists a fracture reactivation pressure lower than the minimum horizontal stress gradient and close to reservoir´s pressure that if is overcome, mud losses take place.
Fractures are discontinuities that create escape paths for drilling fluids and thereby constitute an important mechanism of lost circulation. Most rocks contain fractures of various sizes from micro cracks at grain level to fractures extending for hundreds of feet in the reservoir. In some reservoirs, fractures provide important pathways for the reservoir fluids. Connectivity of the fracture network is its essential property. In the lost circulation context, it affects how much drilling fluid can be lost. In natural fractured reservoirs, the availability of a connected fracture system is essential for production, but is detrimental for drilling (Lavrov A, 2016).
SUMMARY: During the initial evaluation phase of an exploration project in unconventional reservoirs the intervals that will be completed should be prioritized, as a consequence, it is necessary to create a methodology to optimize the selection of intervals for stimulating. This selection is made more difficult at the beginning of the exploratory phase, especially in very thick formations (greater than 500 ft), where there may be several prospective intervals from the point of view of rock quality. Initial tests in vertical wells have a higher investment risk associated with the completion of unfavorable horizons for fracturing, i.e. failures during execution the hydraulic fracturing or great difficulty for proppant admission, therefore an inefficient fracture is created for migration of reservoir fluids into the well. As a result of interdisciplinary work, a methodology for selecting horizons with greater probability of success in hydraulic fracturing (under the Colombian tectonic environment) and for incorporating resources in a vertical well in an unconventional reservoir that has several prospective horizons was generated. Additionally, for the horizons with potential production of gas and gas condensate, a prioritization criterion was established, taking into account the effect of pore pressure decline on the matrix permeability (stress sensitivity).
The proposed methodology is based on: a) generate and interpret an anisotropic geomechanical model, b) selecting intervals that meet the quality criterion for completion in terms of elastic properties, c) generate a probabilistic solution for the distribution of the minimal horizontal stress, fracture gradient and net pressure, d) classifying selected intervals based on the likelihood of having a favorable complexity fracture, e) classifying the intervals in terms of mobility of fluids in the reservoir, f) sorting the prospective intervals in terms of value generation associated with each resource. By applying the methodology it is achieved for example discard prospective horizons with good rock quality, high probability of success of completion but low incorporation of resources, another possibility is to discard horizons with good rock quality, good fluid quality but low probability of successful completion. As a result of the exercise the operator managed to prioritize investment in 3 of the 6 prospective horizons for completion and testing.