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 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.
This paper describes the measures undertaken to increase the run life of sucker rod pump (SRP) installations in the past five years in OMV Austria. Around 500 wells are currently operated with SRPs with an average water cut of 95%. Recurrent pump failures, caused by corrosion, mechanical wear, gas and sand production, significantly contribute to the operating expenditures of a mature oil field operator. In the current low oil price environment the key strategy for economic oil production is seen in efficient low cost production optimization of the subsurface pump equipment. The primary objective was to reduce the life cycle cost (LCC) and deferred production - however, also the increase of production efficiency is an appreciated secondary effect. Consequently, the failure analysis was completely revised and historic data was fed into a new database. A new process was implemented - starting with equipment details, determination of both failure cause and reason and resulting in a ranking for a detailed root cause analysis. The results obtained from the failure analysis led to a profound understanding and rendered a prioritization of necessary actions possible. The optimization measures include design modifications, a stricter quality assurance of new pumps, material upgrades and special pump parts for the respective production environment. In addition an economic assessment of the LCC was conducted in order to quantify the cost impact of pump optimization. The new failure statistic highlights the importance of certain failure modes. Accordingly the necessary pump upgrades were ranked, analyzed and successively executed. The continuous study already shows a change of failure proportions and furthermore improved the in-house knowledge. Even though deploying SRPs for more than 60 years, a structured failure analysis led to new insights of material weaknesses. The introduction of non-API special parts allowed the customization of standard pumps in order to fit to the actual production environment and significantly enlarged the application area of SRPs. In-house material technology center and research laboratory offered valuable information for the root cause analysis. This created the basis for a stricter material specification than demanded by the API 11AX to avoid recurrent systematic failures.
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