A methodology was developed to generate a risked IPR, using a probabilistic Monte Carlo approach and Tornado sensitivity plots for oil wells, to understand the impact of uncertainty on the reservoir and well input parameters. Well model was built to calculate potential flow rates for different probability cases (P10, P50, P90) and different lengths of horizontal well sections using the risked based PI’s generated using Babu & Odeh model. In addition, case studies for the specific input parameters have been conducted to provide selection guidelines for an appropriate estimation of the PI. Case study in heavy oil reservoir has been conducted for vertical and horizontal oil wells to estimate the PI and create the IPR curves for well performance calculations. Tornado plots were used to identify the most critical input parameters affecting well performance. In the horizontal well case, the optimum length of a horizontal well in a heavy oil reservoir was estimated to predict the maximum possible oil production rate with a predicted PI value. In the vertical oil well case, risked based IPR curves were generated to evaluate the production potential of each zone in a heavy oil reservoir. Drawdown modelling for the appraisal well has been completed for a range of horizontal well lengths and for different artificial lift options (natural flow, Gas Lift, ESPs and Jet Pumps). The application of artificial lift has more of an impact at well lengths above 450 m (1500 ft) with ESP and Jet Pump showing better performance compared to the jet pump. In summary, based on the P50 performance curve the current 700 m (2300 ft) well design with artificial lift could deliver 1400 – 1500 bopd which is 200 – 300 bopd incremental in a naturally flowing well.
The application of Progressing cavity pump (PCP) technology for production of oil wells in general, continues to expand rapidly due to ongoing advances in versatility, production rate, lift capacity, durability, and economic reasons. Also, the PCPs have proven to be a successful and reliable artificial lift system for production of heavy oil fields for over 30 years. Because of well conditions, the PCP elastomer will undergo chemical and/or mechanical degradation over time. The insert PCP was designed to significantly reduce the work-over times and lost production associated with pump replacement. Both are costs that significantly affect the profitability of E&P companies. This paper describes the successful implementation and operation of Insert PCP systems in the extra heavy oil wells located along the northern coast of Cuba since February 2008. The field experience includes numerous tubing PCPs installations over the past 11 years, as well as the deployment of several insert PCPs. This paper also compares the pump run life, service rig work-over times and reduction on lost production achieved with the Insert PCPs when compare to conventional tubing deployed PCPs in the same application. In general, the field trial results have demonstrated that there are tremendous benefits to using this technology.
Downhole gas separators are ubiquitous devices needed for the proper functioning of subsurface pumps. Contrasting its widespread use, the knowledge of its performance is quite limited. In fact, little information is available on literature related to testing of downhole gas separators with heavy oil. In the meantime, being able to predict the amount of free gas that will be separated is a key factor for a suitable artificial lift equipment selection. This paper describes the laboratory tests of poor boy and helical separators that are currently being installed in Orinoco Oil Belt heavy oil wells. The “poor boy” design is perhaps the simplest static separator using in the petroleum industry while helical has a sophisticated design. Tests were carried out using ISO 150 mineral oil and air as working fluids in a large scale experimental facility composed by 7 in casing and 3 ½ production tubing. The experimental plan included tests at 80 psig with liquid and gas rates between 200–500 bpd and 33000–137000 scfd respectively. At testing conditions poor boy separator showed a far better efficiency separation than helical separator. The performance of poor boy separator presented a high, nearly constant, efficiency zone for low liquid flow rates. A simple formula for poor boy separation efficiency calculation at the aforementioned experimental conditions is provided. Use of these results will allow a more precise pump sizing, especially for oil wells with high gas production and continuous flow downhole pumps such as progressive cavity pumps.