This paper presents the development and implementation of a production and power optimization system supported by a nodal analysis simulation tool and an updated and calibrated multiphase flow hydraulic model.
The workflow implemented in Castilla field identifies operating conditions that may affect the performance of 577 production wells configured in a complex gathering system, managing multiphase flow for heavy oil with low gas oil ratio and high water cut. Initially, this involves the development of a tool for the systematic data transfer from official databases to the simulation model. Furthermore, the hydraulic model was calibrated to reproduce operating conditions. And once the main nodes and boundary conditions at reservoir, wells, network and processing facility were defined, various optimization scenarios were simulated.
With this workflow the field engineers are capable to propose operating changes to increase production taking into consideration network bottlenecks, power consumption, and facilities limitations. The wells with electrical submersible pumps were ranked into the following categories: pump speed variation, well redesign, surface facilities improvement and drawdown limitation. As a result, actions to be implemented in each well were defined. First, ‘pump speed variation’ classified wells quickly demonstrated how the production and power optimization procedure benefit the field. Specifically, it was possible to optimize the extraction process by increasing the oil production up to 10% using power efficiently. Second, several bottlenecks on the network were identified finding atypical pressure drops, using traditional nodal analysis for pressure, temperatures, velocities, and liquid rates calculation per node. Some of them are related to mechanical configuration and others gas accumulation in pipelines. Third, according to the simulation results, a considerable amount of production can be gained and power consumption can be reduced if these conditions are solved.
This workflow contributes to optimize power consumption and enables faster decision-making to efficiently meet the production targets by increasing oil production and reducing water/oil and power/oil ratios.
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: The mud losses events in the reservoir phase at Castilla field (Colombia – South America) during drilling campaign of 77 wells in 2015 represented an overrun close to $20 MMUS and an accumulated volume of 160.000 bbls of drilling mud lost in the hole. The main reason of these events are associated to crossing structural lineaments during drilling such as faults and set of natural fractures together with the already depleted reservoir sandstone, which results in a drop of the magnitude of the minimum horizontal stress also known as closure pressure of such natural fractures. As a result of the decreased magnitude of the minimum horizontal stress, the natural fractures are considered to be in a critical state of stress increasing the risk of having mud losses through the opened natural fractures. Ecopetrol’s geomechanics team has led the visualization and conceptualization of such mud losses events from ant-tracking models got from seismic data and plotted on the prospects wells surveys. A total of 18 wells scattered in the field were analyzed using the proposed methodology in this paper showing 78% of effectiveness of the prediction mud losses during drilling.
Based on the analysis of the drilling history of 442 wells drilled from 2005 to 2015 it was possible to point that 17.5% of the time was associated to non-productive time (NPT) and 18% of it was due to mud losses events. In Ecopetrol’s oil fields seismic attributes have never been used before to perform root cause analysis of mud losses events in reservoirs with high fracture density. Detailed seismic structural interpretations have been developed in order to improve the root cause analysis of the mud losses events in the reservoir phase using seismic attributes such as ant-tracking having in mind that these attributes are specific measurements of geometrical, cinematic, dynamic or static features that come from seismic data and are mainly used to quantify the amplitude and geomorphological features seen in seismic data.
An important factor during the life of a heavy crude reservoir is the oil mobility. It depends on two factors, oil viscosity and oil relative permeability. Two characteristics of nanoparticles that make them attractive for assisting IOR and EOR processes are their size (1 to 100 nm) and ability to manipulate their behavior. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the surface of the particle, indicating an increasing in surface energy. Nanoparticles are also able to flow through typical reservoir pore spaces with sizes at or below 1 micron without the risk to block the pore space. Nanofluids or "smart fluids" can be designed by tuning nanoparticle properties, and are prepared by adding small concentrations of nanoparticles to a liquid phase in order to enhance or improve some of the fluid properties. However the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present the field evaluation of nanofluids for improving oil mobility and mitigate alteration of wettability in two Colombian heavy oil fields; Castilla and Chichimene. Asphaltenes sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil based nanofluid (OBN) containing these nanoparticles was evaluated as viscosity reducer under static conditions. Displacement tests through a porous media in core plugs from Castilla and Chichimene at reservoir conditions were also performed. OBN was evaluated to reduce oil viscosity varying oil temperature and water content. Maximum change in oil viscosity is achieved at 122°F and 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests, caused by the removal of asphaltenes from the aggregation system, reduction of oil viscosity, and the effective restoration of original core wettability. Two field trials were performed in Castilla (CNA and CNB wells), by forcing 200 bbl and 150 bbl of nanofluid respectively as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 270 bopd in CNA and 280 bopd in CNB and BSW reductions of ~11% were observed. In Chichimene also two trials were performed (CHA and CHB), by forcing 86 bbl of and 107 bbl of nanofluid as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 310 bopd in CHA and 87 bopd in CHB were achieved not BSW reduction has been observed yet. Interventions were performed few months ago and long term effects are still under evaluation. Results look promising making possible to think extending application of nanofluid in other wells in these fields.
Multilateral wells have been routinely drilled for several applications, with shale plays representing a natural progression for its use. Augmenting a multilateral well with selective fracturing of each leg is as straightforward as fracturing a single horizontal well. Multilateral wells with cemented junctions provide a good alternative to improve the economics for the development of oil and gas shale-reserve projects. This paper provides a description of the primary reasons for improving development project economics.
Multilateral solutions provide the means to work within a limited surface access area and generate a reduced footprint while draining a much larger volume of the reservoir from a single-surface location. This solution presents a significant advantage when drilling in sensitive or restricted locations, populated areas, and areas in which land issues restrict access to multiple drilling locations. In addition, the cost and effects of large drilling pads or multiple wellsites are avoided.
This paper describes the results obtained from the implementation and execution of projects in which cemented junctions were created for a new dual-lateral well and for an existing well in North America. It also provides the average cost savings obtained when this approach is compared to that of a single main wellbore and describes well performance with commingled production rates above typical single horizontal wells.
Based on past experience, the use of multilateral wells with cemented junctions (applied for new and/or existing wells) can make significant contributions toward helping oil and gas shale-reserve projects to be economically feasible, whereas the economics of single horizontal wells do not offer advantages for a large development plan for oil-and-gas-industry operators.
Hydraulic fracturing is the most common stimulation technique to make hydrocarbon production feasible and optimal worldwide. However, it has been preferentially focused on low permeability formations, and when applied to high permeability, it has been focused on sand control. This article outlines the process and results of the hydraulic fracturing campaign for productivity purposes (not for sand control) in the basin of the eastern plains of Colombia given the petrophysical characteristics of the cretaceous formations, where thinking out of the box and separating from the existing premises, resulted in successful implementation of this technique in high permeability wells ( 1D), high water cuts (up to 80% BSW) and heavy oil reservoirs (9-12 API).
Mechanical properties play a relevant role, during a successful fracturing job, planning and execution. Geomechanical parameters are valuable information, in order to select the most convenient intervals, to perform the fracturing job, and estimate the theoretical fracturing height results. Additional tools are essential in order to evaluate hydraulic fracture effectiveness; these tools will provide important information, related to fracture height, containment and complexity. This paper presents the application of differential cased hole shear anisotropy (DCHSA) methodology, in Chichimene and Castilla Colombian fields, where hydraulic fracture height was determined, based on acoustic logs information. By determining hydraulic fracture height, mechanical barriers can be identified, in some cases these barriers can be acting containing the fracture growth, and planning of following fracture jobs, can be optimized along field. Using differential cased hole shear anisotropy (DCHSA) methodology, a better understanding of post stimulation production results can be obtained, this information helps to reach better calibration of existing geomechanical model, and fracture design can be optimized, in order to improve fracturing planning, for better well production and field development optimization.
This paper has the objective of presenting new technology, ensuring flow in the extra heavy crude field. The idea of this paper is to outline a successful pilot study carried out in the Colombian Eastern Llanos region where the effect of chemical product (flow improver) is exposed during the production of fluids from the pilot study well and the reduction of naphtha injected into the wellhead (diluent used for the movement of the surface crude). As the main fundamental, the modification of the rheology properties of the crude through change in apparent viscosity due to the effect of loads and interfacial molecular tension within the fluid, enabling improved mobility of fluids from the reservoir to production facilities via surfactant resins that interact with the colloidal particles in the crude thus reducing its viscosity. The pilot is divided into two phases, the first phase consists of determining which of the two flow improvers produces the best performance, and the second phase consists of the application of the selected flow improver to reduce the dilution of naphtha, that is used during the processing of crude to reduce its viscosity. Within the study, a financial evaluation is presented for each of the pilot phases, including a revision of the ESP pumps efficiency within different scenarios. Finally one of the most telling conclusions is mentioned, as the flow improver enables the possible reduction of naphtha injection by dilution in values close to -30%, increasing well production to close to 40%.
In a May 2010 evaluation, several facets of Castilla field operations were assessed: current processes, operations, and technologies; the state of drilling operations by use of management indicators; nonproductive time (NPT); field characteristics; and roles and responsibilities of personnel. The objectives were to prioritize processes by importance, create a process guide, develop a new manpower plan, improve communication, and apply technology efficiently.
Sometimes, drilling optimization of an oil well does not come from a new technology or a new drilling tool, but instead, it may come from something as simple as "putting the house in order??. This was the particular case of Castilla Field in Colombia in 2010-2011, where people had believed that all the drilling solutions were already applied. This paper shows how the drilling and completion (D&C) optimization of Castilla field was performed. The main problems were identified, and a model of 5 management strategies was implemented to reduce the D&C timing. The strategies of the model were applied under the following objectives: constant measuring, evaluation and monitoring of drilling indicators; Support field operations with strong drilling engineering planning criteria; Establish only one communication line through the office drilling engineer in charge of the project; Establish short, medium and long term planning and strategies, and then link them together as function of the Technical Limit "TL??, and subsequently as an HSE function.
The initial evaluation was focused in four main areas: time savings & time to optimize, management indicators, human resources, and drilling operations characterization. The leader of the field has changed the current roles of the engineer in charge of the well from a logistics role to a genuine drilling engineer role. The short, medium and long term vision was applied throughout the well, well pad and campaign in advance. The slogan "Drilling the limit is not hurried up?? was created.
The technical limit (TL) goal was reached. The D&C times, and therefore costs, were reduced by up to 32% per year. Savings greater than USD50 million dollar per year were accomplished. The 2010 trial of Castilla field became the model for the rest of fields that are part of the company portfolio.
The degree of field optimization responds to the same extent at the level in which the gaps are found. It is believed that, as well as this model was applied successfully to other fields within the company, it also might also be applied to others companies. This paper resumes a model of 5 management strategies needed to purge and cure some bad habits that are against the D&C optimization in a field.