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Horizontal Infill Well With AICDs Improves Production in Mature Field

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This paper compares the performance of three mature-field horizontal infill wells, one of which is completed with autonomous inflow-control devices (AICDs). Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production; one of these two wells is completed with slotted liners and the other with AICDs. The third horizontal well was placed in an area with higher gas saturation. The AICDs were found to choke back a high amount of fluid and keep the water cut at a stable plateau level.

Field Introduction

Matzen is a supermature oil field northeast of Vienna and is one of the largest onshore oil fields in Europe. The field consists of several stacked reservoirs, of which the 16th Tortonian horizon (16.TH) is the largest. The westernmost part of the 16.TH is called the Bockfliess area. In this area, 77 wells are currently active: 62 are production wells and 15 are injection wells. During 2011 to 2015, the last major field-redevelopment project in the area, with the objective of doubling the gross production rate, was executed. One goal of the project included a conversion from low-rate sucker rod pumps (SRPs) to high-rate electrical submersible pumps (ESPs). Horizontal infill wells were also drilled to optimize the ultimate recovery in the reservoir.

The 16.TH sandstone reservoir lies between –1490 and –1455 m TVDss [total vertical depth subsea (i.e., total vertical depth minus the elevation above mean sea level of the depth reference point of the well)], with excellent permeability and an average porosity of 27%. Reservoir temperature is 60°C and current reservoir pressure is 120 bar. Oil gravity is 25 °API, while oil viscosity is 5 cp. Average water cut exceeds 97%.

AICD Technology

In recent years, several different types of AICDs have been designed. The most common device types are fluidic-diode, electrical-resistivity, and rate-controlled-production (RCP). This paper covers the RCP type. The working principle of RCP AICDs differs from type to type.

The Levitating-Disc AICD. The AICD that is installed in Well BO 208 is an improved version of the RCP. The design works on the principle of a levitating disc. The AICD valve restricts the flow rate of low-viscosity fluids. When gas or water flows through the AICD valve at the same drawdown, the velocity of the water and gas will increase, reducing the dynamic pressure and levitating the disc toward the inlet to choke the flow.

The AICD valve is assembled as part of the sand-screen joint. The reservoir fluids enter the completion through the sand-screen filter and flow into the inflow-control housing where the AICD is mounted. The fluids then flow into the production stream to the surface together with the production from the rest of the screens.

Horizontal Wells and Completions in 16.TH

Three horizontal infill wells supported the redevelopment project, each of them with a different completion. Of the three, Wells BO 204 and BO 208 can be compared more reliably with one another, whereas Well BO 205 is not a perfect candidate for comparison with the other two wells.

Well BO 204. Drilled in 2013, this was the first well in this series.

Well Target. The goal was to penetrate approximately 530 m horizontally in the top of the reservoir sand to achieve maximum access to attic oil.

Drilling Technique. The well was drilled with real-time geosteering to keep the well path as close as possible to the reservoir top.

Completion. Zones for inflow were completed with slotted liners, while zones for shutoff were completed with blind pipes. Oil and water swellable external casing packers were used between to isolate the different zones. In total, approximately 270 m are open for inflow in three zones, whereas the remaining 260 m are immediately kept out of production because of high ­water-saturation values in the logs.

Production. The well was planned for high gross production rates from the beginning. Well BO 204 was planned to run an ESP with a gross production capability of 2400 m3/d. The drilling path was chosen such that a maximum dogleg severity of 3°/30 m was allowed, as well as a tangent section of 100 m with no doglegs for future positioning of the ESPs.

Well BO 208. Drilled in 2015, this was the third well in this series.

Well Target. The goal was to penetrate approximately 600 m horizontally in the top of the reservoir sand in the eastern compartment of the Bockfliess area to achieve maximum access to attic oil. In reality, only 390 m of the reservoir section could be drilled.

Drilling Technique. The well was drilled with real-time geosteering to keep the well path as close as possible to the reservoir top.

Completion. Zones for inflow are equipped with three different types of AICDs, while zones for shutoff are completed with blind pipes. In between, to isolate different zones, oil and water swellable external casing packers were used. In total, approximately 208 m were opened for inflow in three zones. The remaining 182 m were immediately kept out of production because of high water-saturation values in the logs.

Production. The production strategy for this well is similar to that of Well BO 204, and it was also drilled similarly, including a bigger production casing than usual and an ESP tangent section.

Well BO 208: AICD Planning and Design

Well BO 208 is in the same compartment as Well BO 204. Well BO 204 already was designated with a “poor-boy” restriction of flow in areas where encountered water saturation was very high. These areas were blanked out from contribution to production with blind pipes. To restrict flow in the annulus, oil and water swelling packers were used. The remaining favored zones were ­completed with slotted liners. In the planning phase of Well BO 208, the decision was made to use AICDs. Results from a commercial reservoir simulator were used within a package specialized for completion design. The AICDs were placed in accordance with analysis derived from logged saturations and porosities and with an updated completion-design solution.

Well BO 208: Drilling Plan vs. Reality

The well was planned to connect two local highs in the reservoir. The well path was planned to be approximately 600 m in the reservoir section. In the summer of 2015, drilling was executed. When approaching the target reservoir of 16.TH, the multidisciplinary team found the wait to be much longer than expected. The top of the sand was encountered 160 m later, and on average 7–8 m TVDss deeper, than expected. As soon as the reservoir was reached, the bit was steered upward to stay in the attic of the reservoir. Fig. 1 compares the planned and actual well path and geology for the well.

Fig. 1—Combination of the predrilling and postdrilling situation.

 

The planned well path would not have hit the reservoir until the last few meters. In other words, without real-time geosteering, this well would have been, most likely, a dry well. Compared with Well BO 204, the newer Well BO 208 has a path 6 to 10 m deeper. It was concluded that subseismic faults must have occurred in the location of the well. Despite these obstacles, the decision was taken to complete the well and to put it in production.

AICD Placement

Preparation for AICD placement had to be completed in a short time frame. The preliminary plan was available, but the final design had to be performed immediately after the last logging results arrived at the surface. The real-time data were constantly analyzed by the multidisciplinary team as soon as the bit reached the target reservoir.

In areas where oil mobility is high, more AICDs with larger openings were used. Conversely, the areas with high water mobility were either blanked out with blind pipes or installed with restrictive AICDs that feature very small openings.

Comparison of Horizontal Wells

Wells BO 204 and BO 208 are quite compatible for a comparison, whereas BO 205 is less suitable. The targets of the wells varied. Well BO 205 was planned to be drilled below a former gas cap in a different compartment. Wells BO 204 and BO 208 are used to target attic oil at the top of the reservoir.

The estimated ultimate recovery (EUR) benefits for both compared wells are similar, between 50,000 and 60,000 m³. As it looks today, how­ever, Well BO 208 will have an even higher value than Well BO 204. This result is surprising because Well BO 204 is several meters higher in the reservoir, had a longer horizontal section (approximately 100 m, or 20%, longer), and demonstrated much lower initial water saturations.

The only difference in the operational mode between the two wells is that in Well BO 208, AICDs were installed. In view of the initial facts (much higher water saturation, shorter reservoir exposure), Well BO 208 should have a lower EUR value than Well BO 204, but EUR values are similar. This is a strong indication that the AICDs have a positive effect.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195450, “Horizontal Infill Well With AICDs Improves Production in Mature Field: A Case Study,” by Ilhami Giden, SPE, and Michael Nirtl, SPE, OMV Austria; Hans Thomas Maier, SPE, University of Leoben; and Ismarullizam Mohd Ismail, SPE, Tendeka, prepared for the 2019 SPE Europec featured at the 81st EAGE Annual Conference and Exhibition, London, 3–6 June. The paper has not been peer reviewed.

Horizontal Infill Well With AICDs Improves Production in Mature Field

01 December 2019

Volume: 71 | Issue: 12

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