In the last 10 years, shale gas has emerged as an alternative source because of its contribution to oil and gas reserves. Colombia has a high hydrocarbon potential in unconventional shale gas deposits, and this become the main objective of the national oil industry. Currently proven reserves of conventional gas in Colombia are about 6 TCF, while technically recoverable reserves of shale gas according to the US. Energy Information Administration (EIA) studies 1 are about 55 TCF, so successful production of these reservoirs will increase significantly gas reserves in Colombia.Ecopetrol was the first company in Colombia in starting the characterization of unconventional shales through the stratigraphic well La Luna-1 located in the Medium Magdalena Valley, from which 3445 feet of core were recovered in five months between 2011 and 2012.The need for interpretation frameworks in order to understand properties such as rock source quality, mechanical properties and production performance from a diverse range of measurements require a laboratory characterization of rock properties that is an important part of any resource evaluation. This was the challenge for the labs of the Colombian Petroleum Institute, that based in its experience in Conventional reservoir analysis could adopt its skills and methodologies for analyze 2851 rock samples. The work flow includes geochemical analysis for Total Organic Content (TOC), Pyrolysis Rock Eval VI (parameters S1, S2, Tmax) and quantification of gas content (canister). Samples selection for other analysis was based on core Tomography and Spectral Core Gamma. From the same foot of core, the samples were taken for petrographic analysis, quantitative mineralogical analysis by XRD, mineral distribution and microtexture by SEM, geomechanical Analysis (elastic module and the rock strength), basic petrophysical analysis and Mercury Injection Capillary Pressure (MICP). The information obtained was integrated in order to obtain petrographic rock types, hydraulic rock types and identify the most prospective intervals. The coherence in the parameters obtained by different methods demonstrated the sturdiness of quality system and methodologies applied.
Since its initial discovery in 1975, Offshore Mexico has been the most important oil producing region in the country, with production peaking at 2.8 MBOPD in 2003. However, since 2004, production has been quickly dropping and showing signs of field maturity; current production rate is at 1.8 MBOPD. Coiled tubing (CT) intervention had been typically required to keep production rates steady or even achieve improvement. In 2003, the operator and CT service provider formed a joint venture to put efforts to enable innovative solutions for addressing the challenges of this region. The document discusses the various industry drivers that necessitated service improvements and technology introductions for successful CT well intervention over the last ten years. This paper focuses on the following areas: Drilling and workover environment: Extension of CT interventions in low-pressures to high-pressure wells (self imposed maximum potential wellhead pressures above 3,500-psi) Expansion of Offshore rigless interventions (from conventional operations on fixed platforms to boat-based operations) Extension of CT interventions from fixed-deck to deepwater floater operations CT Applications Conformance applications for water shut-offs and subsequent new perforations Logging interventions in long horizontal sections Real time downhole measurements during well interventions with CT equipped with fiber optic telemetry systems replacing downhole memory gauges CT Equipment Improvements Surface equipment improvements from conventional CT equipment to "latest generation" automated CT unit with active process control and safety systems In summary, this paper presents an overview of the past, a review of the present and discussion of the anticipated future of CT services in the Offshore Mexico region in the context of short, medium and long term technical challenges are presented in several case studies.
Over the last years the oil and gas Mexican operator's exploration and development programs are becoming more challenging due to the complex conditions where hydrocarbons are found today. One of the areas that have seen a decline on production over the years is the offshore. As an alternative to find new sources of oil that overcome the current production decline in the area, the operator is drilling new wells where the operational capabilities of the equipment are put out of their limits. These new wells are drilled at depths beyond the conventional 5,000-m (16,400-ft) with bottom hole pressures as high as 15,000-psi and temperature over 180ºC requiring that the equipment providing the services over their producing life reach their own limitations and in some cases re-engineering of the design and process has to be done.In some cases, minimum changes to the equipment or processes are enough; however, a service of such complexity as the use of Coiled Tubing (CT) requires a major review of all the components of the operation to be completed in order to reach the new targets without jeopardizing the safety of the operations and/or compromising the production of the well. This paper details the CT string design criteria to reach the deeper vertical depths with high wellbore mechanical friction coefficients while withstanding high pressures; equipment selection, to allow greater CT length capacity on reel and higher pulling capacity on injector head; platform and crane specifications to withstand over dimensioned equipment, as well as, a case study to analyze equipment and CT string performance for interventions on these types of wells.
Coiled tubing (CT) operated from a floating anchored vessel (FAV) was developed for well intervention in offshore locations where crane limitations and deck loading constrains imposes various limitations on the ability to perform workover operations. This tailor-made solution involves the operation of a CT unit with the tubing reel located on a FAV and the injector head positioned on the offshore platform. Today, CT operations supported by a FAV are routinely performed in several countries, including Malaysia, Gabon, Tunisia, Brunei, Angola and the North Sea. The first CT operation supported with a vessel in the Gulf of Mexico was successfully performed in a non-producing well which had been shut-in for nine months due to compatibility issues with the structure for temporary installing service equipment and and the limited availability of jack-up platforms to provide a deck area for positioning CT equipment. As result of this successful operation, a new perspective of CT rigless interventions was adopted in offshore Mexico, thus allowing the operator to improve equipment utilization for both CT units and workover rigs, in order to maximize oil production. This paper details the analysis, execution and evaluation of the first CT operation from a FAV in offshore Mexico, which includes equipment selection, sea condition and weather-related studies, contingency planning, personnel competency and training requirements, and logistical considerations, among other technical factors that were critical in the implementation of such project. As well, the benefits that were realized by the operator regarding production enhancement and operational cost reduction are covered.
It is estimated that 70% of the world's oil and gas reserves are contained in reservoirs where sand production is or will become, a problem during the life of the field (Chen et al., 2010). Consequently, an effective sand management strategy may be critical to assure hydrocarbon production. This study presents some results of a developed sand prediction model that has been used in Venezuela to understand sand transport characteristics in heavy oil and to estimate suspension and deposit critical velocities. In addition, results are presented of a sensitivity analysis of particle diameter and water cut carried out using a dynamic multiphase flow simulator to determine the accumulated solids content in some pipelines that helped to develop adequate cleanup procedures. Pressure/volume/temperature (PVT) analyses were initially conducted in order to to reproduce the field characteristics of the produced fluid, including diluted fluid. Sensitivity studies were done to evaluate the effects of some parameters, such as grain size, flow rate, and water cut, to determine how they affect critical transport velocities. From these studies, the volume of particles deposited and the thicknesses of these deposits were determined, which helped the operator to define appropriate pigging program to remove sediments and to estimate the effect on the production system without an appropriate cleanup activity. The initial result shows that the network gathering system operates below deposition critical velocity, however, a stationary sand bed is growing in pipelines near the wells. In addition, the parametric studies revealed that when the particle sizes increase, the critical velocities increase. Besides that, critical velocity shows different behavior with water cut. Critical velocity increases when the water cut goes from 0% to 5%, but if this maximum value is overcome, the critical velocities decrease. Field data indicated that the amount of material received at the end of the system (CPF) during 500 days is 1600 tons of sand, but the maximum operation allowable pressure is reached 290 days after starting up the oil production. Dynamic flow simulations indicated that it is necessary to start the cleaning operation between 150 and 290 days after the start of production, depending on the available pressure to push the pig. This paper summarizes the novel contribution of using dynamic flow simulations for sand prediction and a control model in one of the growing joint venture companies in FAJA PetroIndependencia in Venezuela. Prediction of critical flow rate to prevent sand settling is important for flowlines that are in the design stage. This paper offers a valid approach to extend the predicted sand critical velocities to other fields in FAJA with similar crude conditions to aid in pipeline design.
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