Managers tend to avoid costs and production losses related to data acquisition. Pressure and rate transient analyses (PTA and RTA) along extended production time allow reservoir characterization and understanding of near-wellbore characteristics; however, PTA and RTA alone do not provide pressure- and fluid-distribution prediction beyond the wellbore. Such a task requires integration with reservoir simulation.
Well testing is today a main procedure for verifying reservoir, well and fluid properties such as permeability, skin effect, average reservoir pressure, heterogeneities, boundaries and hydraulic connectivity. We present in this work a methodology based on numerical optimization and statistical methods to get an accurate and reliable Naturally Fractured Carbonate Vuggy Reservoir Characterization, using a Triple Porosity-Double Permeability Model. A sensitivity analysis is performed to identify the effect and magnitude on the pressure of each parameter involved in the model to reduce the error estimation and to eliminate multiple interpretations due to numerical precision. We also introduce a robust regularization method to control noise propagation contained in pressure data for improving well test analysis. The efficiency and accuracy of the proposed approach is demonstrated by implementing the triple porosity-double permeability model as compared with the traditional double-porosity model used in commercial software. Furthermore, not only the accuracy of the fit is compared but also the amount of reservoir information obtained when using the Triple Porosity-Double Permeability model, as we identify nine parameters in the case of totally penetrated wells and eleven parameters in the case of partially penetrated wells. Results are illustrated with transient well tests of real carbonate fractured vuggy reservoirs from Mexico.
Jamal, Mariam (Kuwait Oil Company) | Anthony, Elred (Kuwait Oil Company) | Chetri, Hom B (Kuwait Oil Company) | EL-Din Ibrahim, Hossam (Kuwait Oil Company) | Kumar, Priya ranjan (Kuwait Oil Company) | Nair, Sajan (Kuwait Oil Company) | Al-Zaabi, Hamad (Kuwait Oil Company)
Within a natural fractured Carbonate Reservoir a NOC’s Overall production rates are constantly challenged with factors, such as high permeability streaks, poor macroscopic sweep efficiency, and low mobility ratios, all of which can dramatically impair production rates and reservoir oil recoveries.
This paper presents the experiences from managing said reservoir using traditional reservoir engineering sound practices and latest digital technologies of IDOF.
We describe in recent years how a collaborative and multi-disciplinary team implemented a series OF BEST PRACTICE reservoir-to-surface surveillance practices which include:
(1) water flood-front monitoring through wellbore resistivity and seismic methods,
(2) injector-producer connectivity mapping through tracer tests complemented with data-drive analytics, numeric and streamline simulation,
(3) Well performance and productivity watching via real-time data processing, analysis, modeling and optimization,
(4) Water flood displacement and volumetric efficiency following up through continuous reservoir shut-in pressure data capture or estimation via multi-rate testing and permanent down hole gauges installations.
Data and consistently applied work processes are orchestrated through digital technologies which include workflow management and integrated visualization, allow making well-informed, real time decisions to optimum reservoir recovery management.
These actions included
(1) the identification of various infill drilling opportunities of vertical, horizontal and multilateral wells,
(2) optimum allocation of water injection and production allowable and (3) recommendation for water-shut-off and water conformance jobs.
More than 70% of global oil production derives from mature fields. With current elevated prices, the revitalization and optimization of these fields are of great commercial appeal and interest. However, revitalization requires technologies and procedures for quick analysis and diagnosis of the field in addition to established technical solutions to help improve productivity and counter high levels of pressure and production decline. In 2013, in the southern region of Mexico, workflow integration for integral analysis of well productivity in mature fields and naturally fractured carbonate reservoirs, in combination with joint efforts of several product service lines and their technological solutions, have been key to identifying a portfolio of opportunities for well interventions. Of which, in a short time period, an increase to production of 1, 843 STB/D of oil was achieved, with only 54.5% of the proposed activity involving well services. In view of the energy requirements in the world and the low rate of discovery of new reserves, many companies have targeted maximizing the exploitation of mature fields. Therefore, this study intends to establish effective techniques, methodologies, best practices, and lessons learned developed by multidisciplinary teams performed in Mexico during the past eight years. This strategy has helped increase oil and gas production in areas where it was previously considered unlikely because of complexity issues, such as low pressures, low permeability, organic deposits, scales, advanced fluid, reservoir dynamics, and mechanical problems, among others. These efforts have resulted in highly successful solutions as well as added value to the national operator.
The need to develop new tools that allow reservoir engineers to optimize reservoir performance is becoming more demanding by the day. One of the most challenging and influential problems facing reservoir engineers is well placement optimization.
The North Kuwait field (NKF) consists of six fields containing four naturally fractured carbonate formations. The reservoirs are composed of relatively tight limestone and dolomite embedded with anhydrate and shale. The fields are divided into isolated compartments based on fault zones and supported by a combination of different fluid compositions, initial pressures, and estimated free-water levels. Due to natural complexity, tightness, and high drilling costs of wells in the NKF, it is very important to identify the sweet spots and the optimum well locations.
This paper presents two intelligent methods that use dynamic numerical simulation model results and static reservoir properties to identify zones with a high-production potential: reservoir opportunity index (ROI) and simulation opportunity index (SOI). The Petrel* E&P software platform was chosen as the integrated platform to implement the workflow. The fit-for-purpose time dependent 2D maps generated by the Petrel platform facilitated the decision-making process used for locating new wells in the dominant flow system and provided immense support for field-development plans.
The difference between the two methods is insignificant because of reservoir tightness, limited interference, and natural uncertainty on compartmentalization. At this stage, pressure is not a key parameter. As a result, unlike brown fields, less weight was given to simulated pressure, and SOI was used to select the well locations.
The results of this study show that implementing these workflows and obtaining the resulting maps significantly improve the selection process to identify the most productive areas and layers in a field. Also, the optimum numbers of wells using this method obtained in less time and with fewer resources are compared with results using traditional industry approaches.
Long horizontal open holes and naturally fractured reservoirs have always presented a challenge to the industry for successful matrix treatment operations. This is particularly true in western Canada where the reservoirs are competent carbonate formations completed open hole over a length of 2,000 m with a bottomhole static temperature of 110°C. These naturally fractured formations exhibit substantial and unpredictable permeability variations over the length of the interval. During treatment, all or part of the acid may thief to a high-permeability interval leaving the rest of the wellbore poorly stimulated. The industry has developed a range of products and techniques to divert the stimulation treatments from these thief zones in an attempt to improve wellbore coverage and reservoir drainage. However, the placement of these diverting techniques and the evaluation in situ and in real time of their effectiveness were yet to be accomplished.
An innovative technique, developed in Western Canada, combines state of the art viscoelastic acid diversion with fiber optic technology for accurate downhole fluid placement and optimum diversion effectiveness. This is a unique system consisting of live downhole temperature and pressure measurements transmitted to surface through fiber optic telemetry installed in the coiled tubing (CT). Real-time analysis of distributed temperature survey (DTS) and single-point downhole measurement of temperature and pressure, along with petrophysical data, provide an in-situ visualization of the dominant thief zones. The analysis of this information allows for on-the-fly adjustment to the diversion placement schedule matching current downhole conditions.
This technique provides a unique way to ensure the entire pay zone is fully and homogeneously stimulated, optimizing the reservoir contact and delivering the full well potential. The technique was systematically applied to all newly drilled wells in the Suncor Panther field in the western Canadian Rocky Mountain foothills. The comparison of gas production over the entire field for 16 new wells illustrates that results have substantially improved since the introduction of this innovative technique.