The objective of this paper is to describe a comprehensive approach integrating static and dynamic well characterization to optimize well completion and subsequent improving oil production in thin sand reservoirs.The following procedure was used to estimate and optimize the production potential of 3 feet sand reservoir located in Limoncocha Field:• Accurate well logging program to identify thin sands. (Vertical Resolution, Static Data) • Open Hole Mini DST program to estimate permeability, skin effect, and reservoir pressure and productivity index. (Dynamic Data) • Anchored guns with 800 psi of static underbalance to avoid control fluid invasion. • Well completion done with drilling rig; No well test is required using this methodology. • PVT sample taken in cased hole for further characterization and continuous improvement.
The objective of this work is to describe a comprehensive approach integrating static and dynamic data along with rock mechanical properties to optimize well production and avoiding premature sanding problems. The proposed procedure was used to estimate the production potential of a slanted well in the Napo M1 Sandstone which presents a high sanding potential. Starting with a detailed petrophysical analysis along with advanced sonic scanner data processing, a Mechanical Earth Model (MEM) was built. In addition to the MEM an advanced perforating design and a grain size laboratory test were finally used to develop a Sanding Model Analysis that was used to predict and measure severity of sanding problems under specific static and dynamic conditions. This holistic approach was used to determine the critical drawdown at which sanding problems could occur. A tailored critical drawdown was determined based on grain size; it was determined that small grains will start moving with drawdown of around 790 psi, while larger grain sizes will move at a drawdown close to 1790 psi. The grain size distribution per sample was then used to determine the level of severity and safe and non-safe drawdown ranges. Finally a safe bottom hole flowing pressure of ~1100 psi or drawdown of ~1190 psi with a 90% safety of no sanding problems was selected as the optimum dynamic condition for producing the well with minimum sanding risk. The well was put into production using the recommended critical drawdown. No sand production was observed at the surface. After five months of production (from 30-Aug-2014 to 4-Jan-2015), the well had accumulated 9 bbls of sand (equivalent weight: 3650 kg), lower than expected (not showing on surface) and average production was 1126 bbls of fluid per day (1075 bbls of Oil per day, 4.53% water cut), significantly higher than neighbor wells. This methodology accurately predicted the critical drawdown at which a well with potential sanding problems must be produced. It also provided highly valuable information for a better completions design and decision making on whether to use a sand control equipment or not, representing cost savings and optimizing production.
It is a common practice to evaluate an injection pilot before a field-level implementation of waterflooding, but this requires early investment in facilities and construction time. An alternative solution is proposed as a modification of the dump flooding concept: Produce water from a low-salinity aquifer and inject it into an oil reservoir within the same well, using a closed system. The modification of the conventional dump flooding design consists of adding surface monitoring and control capabilities, which for this mature field is a local regulatory requirement A comprehensive process for the completion design considered reservoir, well and operational conditions as both new and existing wells were considered as candidates for these completion systems. The design consists of a concentric completion with packers to isolate both the water aquifer and oil reservoir. Water is produced from a deeper low-salinity aquifer with excellent water quality through an Electric Submersible Pump (ESP) that also serves as an injection pump. At surface, the water rate is measured by a flowmeter and then injected into the same well through a concentric string to a shallower oil reservoir for secondary recovery. A simple closed-loop system at surface eliminates contact with oxygen, minimizing future corrosion problems. The high quality of the water (low salinity, without solids, O2, H2S or Fe) eliminated the need for water treatment. Four wells have been successfully completed using this design, currently injecting at the required rates without presenting any functionality problem. Additional three wells are in schedule to be completed in order to accelerate waterflooding implementation in areas either remote or environmentally sensitive with no nearby water source. In these areas, implementing a waterflooding conventional pattern that requires connecting water producers and injector wells would require lengthy permission processes for long high-pressure lines and additional time for the construction of those water transport pipelines. The completed modified dump flooding wells decreased the implementation time of the waterflooding pilot project from 2.5 years to 5 months. Additionally, the environmental footprint and facilities investment has been reduced by an estimated 90%. This is the estimated cost savings when comparing the investment in dump flooding well construction versus conversion of existing wells to water producers or injectors and the investment in facilities, including water treatment plants, to connect those wells. This paper presents the main design and operational considerations before execution, deployment challenges, and lessons learned and recommendations from the execution of the first campaign
Petroamazonas EP is the national oil company in Ecuador. It holds most of the oil concessions Onshore and Offshore in the country. The oil and gas production targets require implementing advanced analysis that provides effective results on production. In order to analyze and predict the well Productivity, it is necessary to perform an appropriate perforating analysis; this can be achieved integrating Petrophysics, Geomechanics, Reservoir and Production Domains. For an advanced Perforating design a clear understanding of rock characteristic, depth of damaged zone and reservoir behavior is used in the Perforating simulation. This enhances the right selection of charges and ensures they will overpass the altered zone. Step by step procedure is described: Petrophysical evaluation and rock strength of the formation of interest. Quantification of alteration depth. Display the penetration profile. All this previous steps are used in order to obtain a detailed Flow Profile. To identify and select with the Flow Profile the better zones to produce. A sensitivity analysis is performed to select the best scenario for a technical and economic decision. This methodology was implemented in two of the key Petroamazonas EP assets, which are Amistad Offshore Gas Field, and Apaika Onshore Oilfiled. This helped to optimize and predict the productivity of the wells. The following conclusions were obtained once the wells were on production: Selection of the better intervals to produce Low Uncertainty of well productivity prediction Confirmed effective communication between borehole and reservoir Skin reduction due to a better perforating selection and design Optimized completion design Making proper decisions when analyzing project cost versus production.
For more than 30 years, most of the fields in Ecuador have reached a high level of maturity that demands several operational and control challenges for multiple processes such as chemical injection, high gas volumes, water cut incremental among many other issues affecting the useful life of downhole equipment installed in the well or devices located on the surface. Furthermore, implementing digital solutions in a field also faces the challenge of allocating faster and agile solutions that add efficiency to production, but at the same time avoid or minimize deferred production for implementation. Fortunately, current digital technologies such as IoT and Edge Computing are combined with cloud applications, controllers and even software to connect and use unimagined solutions for the oil and gas industry. These controls make an easier, faster, and more reliable way guaranteeing the production integrity operations, while reducing carbon footprint and improving work-life balance. Operations case studies in Ecuador will be discussed including not only production engineering analysis but also production operations in the field with a major focus on asset surveillance. Both activities require time-consuming tasks such as field trips and well-by-well analysis, showing the transformation in the way we operate leveraging the use of data, promoting remote operations, and automating the workflows used within the production engineering department. The starting point of this implementation was the well surveillance workflow, carried out at the field level because there was no mature SCADA system. Thus, the Edge was implemented with capabilities based on Internet of Things (IoT) technology to connect the different elements of the production chain. Currently, more than 400 pieces of equipment have been connected to a unified platform, including electro-submersible pumping equipment (ESP), wells with Beam Pumping (BM), injector wells, injection pumps, high-pressure injection equipment, multiphase flow meters and others, which allow us to integrate data, perform real-time analysis and remotely control any equipment that is connected. The impact of this solution is the reduction of production losses by 9%, the reduction of field visits by 23%, the increase in the useful life of the equipment by 32% and the reduction of CO2 emissions by 22.6% in surveillance activities. On the other hand, the integration between the intelligence at the edge and the corresponding instrumentation allowed the creation of two tailored solutions. The first, to automate the annular gas handling process, and the second, to automate and optimize the efficiency of the chemical treatment. The tangible benefits of these solutions are: 12 gas handling equipment operating in the field, resulting in a 12% increase in production compared to wells that do not have the solution, chemical injection accuracy increased up to 99% and corrosion/fouling failures reduced by 50%. Using the benefits of IoT, different applications (more than 14) were implemented such as: flare monitoring and gas volume measurements, virtual flow meter, smart alarms, surveillance of portable multiphase flow meters (Vx Units), pumping equipment of high pressure (HPS) and monitoring and diagnosis of vibrations in rotating equipment
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