The aim of this paper is to compare the performance of three horizontal infill wells in a mature field, of which one is completed with autonomous inflow control devices (AICDs). The analytic results are based on the comparison of oil production rates; water cut development and water-oil ratio plots of the wells. All the wells in this study are producing from the same homogeneous sandstone reservoir. Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production of which one of these wells is completed with slotted liners and the other with AICDs. Both are artificially lifted with high rate electrical submersible pumps (ESPs). The third horizontal well was placed in an area with higher gas saturation, where a completion with casing, cementation and perforation was used. The performance of the horizontal wells is compared against each other. The use of active geo-steering successfully supported the well placement into the "sweet spot" of the reservoir due to real-time well path adjustments. It was found that the AICDs choke back a high amount of fluid and keep the water cut at a stable plateau level. This observation underlines the key benefit of using AICDs as when comparing to the other producing wells without AICDs, the water cut is steadily increasing. Therefore the use of AICDs is a real option for horizontal well completion. This paper will be useful to those who are in a phase of early well planning, e.g. in a field (re-)development project and have to select the best well concept (e.g. slotted liner vs. AICDs). AICDs have proven their value even in a super-mature oil field by improving production. Further advantages and challenges during operation are discussed in this paper.
The objective of the field re-development project of the 16th Tortonian horizon in the Austrian Matzen field was to double gross production. To achieve this goal, some of the formerly used sucker rod pumps and electrical submersible pumps (ESPs) were replaced by high-rate ESPs. Over the course of two years, the field surface and subsurface upgrades were conducted, from the tendering process to the final installation. With the installation of downhole sensors, the foundation for a digital oilfield was implemented. Screening of the reservoir by a multi-disciplinary team generated suitable candidates for gross increases. Therefore, in the pre-project phase, the following steps were undertaken to prove the feasibility of such a large-scale re-development: Two viable candidates were selected as pilot ESP wells to prove the concept. Lessons learned from these candidates provided data for the scope of work of the ESP tender. In order to optimize the ESP operation, the wells were clustered into five groups. For each group one designated ESP type was chosen to cover the new required flow rate range. In two workover campaigns, 39 ESP installations were conducted, with the support of an onsite application engineer from the service company. The approach to double gross production by using high-rate ESPs proved to be feasible. The two pilot wells delivered critical information for the success of the project. Lessons learned regarding design and wellbore integrity were gained. A root cause failure analysis led to enhancements in material selection. By installing this high-volume artificial lift technology, the surface and subsurface infrastructure was refurbished to a new level of automation. This allows engineers to monitor, analyze, optimize, and troubleshoot the system in real-time, independent of location. A close cooperation between the service company and operator from the engineering to execution phase resulted in no early failure and exceptionally good run-life statistics. The sensor data are used to further improve the design and forecast equipment failure. This has a positive effect on economics by reducing the cost of the ESP strings and quantity of backup equipment. The concept of grouping wells was a very practical solution to conduct such a project in a very short time. A key for the smooth implementation of the project was the close collaboration with the service company's onsite application engineer.
The application and implementation of streamline derived rate targets have proven to increase oil production and reduce water cut with minimal investment (Kornberger & Thiele, 2014). The Matzen field, and in particular the 16.TH layer, has significant peripheral water injection as well as a large operating range on the production and injection wells, making it an ideal candidate for streamline based water flood optimization measures. A multidisciplinary approach was taken to modelling the 16.TH, incorporating and analyzing data including pressures, production & injection volumes as well as individual well operational envelopes. Several uncertainties surrounding the field were also addressed in the modelling approach, for example faults and their transmissibilities. As a result, robust streamline derived rate targets could be defined and implemented across approximately 30% of the active wells in the field (around 60 wells), which significantly improved the production performance. Following implementation, the performance was continuously monitored, with impressive results. Implementation of the rate targets, resulted in a field wide daily production rate increase of up to 5%, peaking at 26 m3/day (165 boe/day) with an increase of only 140 m3/day on the liquid production and an increase of 160 m3/day water injection, exceptional for a field with an average water cut of 98%. Despite the positive results, there were several lessons learned that are discussed in the paper and can be applied to future field implementation to improve the performance further. It has been again proven that implementation of streamline derived rate targets can provide significant value, and through a defined workflow and automatic model updates this value can be realized faster, more reliably and with less manpower, offering an effective method of managing a water flooded asset and maximizing its value.
The 16. Tortonian Horizon is one of the largest producing oil reservoirs in continental Europe. The field has been on production since 1949 and has already gone through a long decline period. The average water cut currently exceeds 96%. The western region of this reservoir, called Bockfliess area, was the focus of the latest field re-development effort, aiming to increase oil production by doubling the liquid rate. Although the project comprised various activities – including facility upgrades and the construction of additional surface infrastructure –, this paper focuses mainly on subsurface measures. The majority of modifications were conducted on existing production wells. Quick wins included additional perforations and sucker rod pump (SRP) unit changes. The artificial lift systems of more than one third of the producers were converted to electrical submersible pumps (ESPs). Three new high-rate horizontal producers were also drilled. To maintain reservoir pressure, nearly all the produced water had to be re-injected. Several of the existing producers were converted to injectors and two new horizontal injector wells were drilled. The overall goal of doubling the gross production rate was accomplished by an integrated multidisciplinary team in a short time period. 13 additional perforations, four SRP unit exchanges and 32 conversions of producers to ESPs proved to be successful in increasing oil production. In order to target the remaining attic oil, three high rate horizontal infill producers were effectively placed within specific zones of the reservoir by applying state of the art geosteering technology. The planned voidage replacement ratio was achieved by converting nine producers to injectors and two successfully placed horizontal high rate injector wells. These measures increased oil production by 62% (43% was gained from existing wells and 19% from new wells). The concept of doubling the gross rate on a reservoir scale was unprecedented in Austria, especially for a reservoir that was already producing at maximum surface capacity. For single wells, gross rates were increased up to seven-fold as compared to the rates produced before the project. To control such high volumes with an optimized operation, real-time monitoring of the sensor-equipped ESPs was implemented. Horizontal infill drilling had not been implemented before in the targeted reservoir area due to the close well spacing. Real time geosteering methods using advanced logging while drilling (LWD) technology proved to be beneficial in this onshore mature brown field. Different sand control and bottom hole flowing pressure control methods were applied in each of the new horizontal producers, including autonomous inflow control devices (AICD) which are currently mainly utilized in offshore environments.
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