Efficiently increasing dynamic reservoir evaluation for offshore field appraisals

Dynamic reservoir data are a key driver for offshore operators to meet or exceed the forecasted production plateaus of their fields. However, many challenges during the well testing phase can prevent them from gathering the mission-critical reservoir characterization data that they need to make more informed field development planning decisions that result in optimal production. Some of these challenges include reduced exploration and capex budgets; complex geologic structures; and inclement weather conditions that reduce the well testing time window.

After discovering Neptun and Triton fields in the Sea of Okhotsk, Russia, Gazprom Neft commissioned two appraisal wells in 2018 and 2019 to characterize the reservoir. However, icy conditions and large storms restricted the drilling window, limiting the number of drillstem tests (DSTs) to only four zones, using a traditional downhole testing toolstring. The reason that the tests were capped at four was because traditional methods would have required pulling out of hole (POOH) the toolstring for every zone. 

Due to the anticipated, high bubble point pressure and heterogeneous geologic structures comprising the reservoir, Gazprom Neft required as much subsurface information as possible to reduce uncertainty for making key field appraisal and development planning decisions. This meant that more zones needed to be tested for each of the appraisal wells to get the desired evaluation results, but the tests had to be done more efficiently to satisfy the tight turnaround time.

Schlumberger provided a solution using the Symphony* live downhole reservoir testing platform united by Muzic* wireless telemetry to achieve the required tests in one run—without the need for wireline intervention. The result was a safer and significantly more efficient well testing operation that yielded the dynamic reservoir data that Gazprom Neft needed to de-risk their reserves and optimize the field appraisal program.

TRADITIONAL DOWNHOLE TESTING STRING LIMITATIONS

The challenges associated with acquiring dynamic reservoir information from offshore environments have increased the need for efficient single-run multi-zone and multi-layer well testing operations. To achieve this, however, the traditional downhole testing toolstring had to evolve, because it is not capable of accommodating such tests in a single run, due to the following limitations:

The downhole pressure is recorded in a memory mode. The data quality check and interpretation can be done only after POOH the toolstring, which is not acceptable to assess the reservoir at a certain distance. Alternatively, the downhole pressure can be extracted before POOH the string by using the wireline surface read-out. However, this option is not used extensively in offshore environments, because it increases the rig time and HSE risks associated with well intervention. 

Annulus pressure windows activate the downhole fluid sampler. Under optimal conditions, the samplers can be activated only once, which does not enable gathering samples at different conditions and during multi-zone testing. The worst-case scenario is the sampler cannot be activated at all, because of a lack of pressure windows. In this case, the reservoir fluid sampling is obtained by running the samplers on cable or slickline, and this increases the rig time and HSE risks associated with well intervention. Moreover, the sampler with a traditional toolstring can only be installed above the packer.

Multiple tools need to be run for multi-zone testing. The selective perforation of reservoir intervals for selective multi-zone testing is done by separate running in hole (RIH) of guns, either as part of different toolstrings or on cable. This is used widely on land wells, where the rig cost and risks are low, but this is not acceptable for offshore.

Hydraulic commands can cause difficulties operating downhole tools. The hydraulic commands are dependent on human factor, rig pump and annulus fluid transmissibility. The time to operate the tool may last up to 30 min. from the moment of decision to the moment of tool activation. If a large storm requires shutting in the well immediately, then there is a lost opportunity to record good-quality build-up data at the downhole valve.

Additional running of logging tools is required. Before setting the packer, the operators run logging tools to position the toolstring, to check the status of the downhole tester valve and record the well inflow profile. These operations are associated with well intervention and interaction between different service providers, which are recommended to avoid, especially for offshore operations.

All these limitations in a traditional toolstring drove Schlumberger to introduce the live downhole reservoir testing platform that achieves test objectives with the highest accuracy and operational certainty. It is a comprehensive, self-sufficient platform for testing the reservoir in a single run by positioning the toolstring during RIH; selectively activating the perforating guns; controlling downhole valve operation; measuring the downhole pressure; selectively obtaining the representative samples at the most favorable depth; and enabling zonal selective flow. 

Different modules are united and operated by wireless telemetry. Moreover, the real-time downhole monitoring system provides the verification of operations to rapidly adjust as conditions change; real-time validation of well test quality; and interpretation to obtain the optimal amount of representative data from reservoir. The system improves the operational flexibility and HSE standard by minimizing additional well intervention with cable or slickline, and reduction of involved parties to operate the downhole tools.

EVALUATING A CHALLENGING RESERVOIR IN RUSSIA’S FAR EAST 

After discovering Neptun and Triton fields, it was clear that the Russian Far East region would become a strategic oil-producing cluster for Gazprom Neft. However, the fields required extensive reservoir evaluation before making the decision to invest in the field development. 

The evaluation results of the first exploration well in 2017 showed that the oil reserves were concentrated in six to eight heterogeneous zones with different properties. To gain a more comprehensive understanding of the reservoir, Gazprom Neft needed the ability to test more than three to four zones, which was the maximum number that could be tested using a traditional downhole testing toolstring within a short 30-to-40-day testing window.

Fig. 1. Symphony testing toolstring, used for one of the tests in 2019.

Downhole reservoir fluid sampling is an essential part of any well test. The reservoir fluid of these fields was expected to have a high bubble point pressure, close to initial reservoir pressure. To obtain the representative samples, Gazprom Neft set the requirements to locate the samplers close to reservoir, control and monitor the downhole flow prior to activation, and get samples at different flow regimes.  

The design and execution of pressure transient test without failure is very important, especially when estimating the variation of reservoir properties laterally in a heterogeneous reservoir within the given radius of investigation. This requires monitoring and interpreting the flow and buildup recordings in real time and minimizing any effect of noise masking the reservoir signal, due to gas coming out of oil (high bubble point pressure) in the reservoir and inside wellbore.

INNOVATIVE WELL TESTING SOLUTION

The high cost of exploration activities, and even higher cost of field development offshore, drive optimization of the operation and being certain in obtained results. The geological and operational challenges of Neptun and Triton fields required changing reservoir testing.

The live downhole reservoir testing platform provided the flexibility to control the operations and data interpretation in real time. This minimizes the well intervention and toolstring RIH operations, testing more zones in a safer manner and obtaining all necessary information about reservoir. 

The solution was based on a combination of various live downhole reservoir platform technologies in the toolstring and workflows, Fig. 1. The toolstring consisted of four key elements that leveraged acoustic wireless telemetry to send downhole commands and obtain the data from gauges and the status of each tool.

First, the real-time downhole pressure measurements were performed during the whole testing period. Three gauge carriers were installed at different depths to monitor the pressure in the tubing and annulus below the packer, and below and above the tester valve. This configuration not only enabled interpreting data in real time, but it also was used to check the tester valve integrity and its open/close status at different stages of operations. Moreover, three gauges facilitated calculating the fluid gradient above and below the tester valve, which gave more insights into downhole flow conditions, to estimate the wellbore cleanup efficiency and possible two gas-liquid phase presence.

Second, the single-phase downhole samplers captured independent, redundant downhole reservoir fluid samples via wireless commands. The samples were obtained below the packer and close to reservoir, and sampled selectively at different conditions (flow regimes), to increase the number of samples since the toolstring does not rely on annulus hydraulic command like a conventional toolstring. The system also helped to confirm the sampler activation in near-real time, which was not possible before.

Third, the wireless dual-valve system enhanced the efficiency of the well test operations. Fully compatible for quick and reliable wireless telemetry commands, the system rapidly adjusted for both anticipated and unexpected program maneuvers. This ensured that the reservoir testing was fully independent of annulus hydraulic commands, which take longer and are subject to human error. This system helped improve the efficiency of well start-up operations and high-quality build-up with downhole closure.

Fourth, the firing head selectively activated the perforating guns via acoustic signal. This enabled testing of two zones with a single RIH. This was not possible with traditional firing heads that rely on hydraulic firing heads. The system also enabled firing guns with nitrogen in the tubing to create the initial surge for clean-up and reduce the rig time. 

The combination of the above described technologies helped achieve the results needed from the well testing operation in a more effective way. 

Fig. 2. History of bottomhole pressure and fluid gradient below the tester valve.

Gazprom Neft and Schlumberger developed the downhole fluid sampling methodology for fluid with high bubble point pressure, which combines the downhole real-time monitoring and a new single-phase downhole sampler. The sampling flow regime was set, based on bottomhole pressure and fluid gradient, below the tester valve, Fig. 2. Traditionally, the downhole sampling is obtained by flowing the well at minimum choke size. However, it doesn’t guarantee the representative flow, since the sampling point can be characterized either by gas-oil or oil-water two-phase systems. 

In this workflow, the real-time fluid gradient provided a clearer downhole picture, since noise in the calculated fluid gradient was correlated with the presence of gas at the point of sampling. As a result, the sampling was obtained at the flow regime with highest bottomhole pressure and minimum noise in the fluid gradient. The downhole sampling was done selectively at two different flow regimes, and the sampler installed below the packer was field-tested successfully. The new system can advise the right time to obtain the most representative downhole sample while minimizing the HSE risks and reducing rig time, which is critical for offshore operations. 

Next, a workflow was developed to execute the pressure transient test by minimizing the wellbore storage. This was essential to estimate the lateral variation of petrophysical properties at the scale of less than 164 ft [50 m], which is not usually detected by offshore seismic data. This was achieved by downhole real-time monitoring, the downhole dual-valve system and interpretation. Traditionally, it is assumed that if the well is closed with the downhole valve, it provides the minimum wellbore storage.

Fig. 3. Log-log plots without (left) and with (right) downhole monitoring.

However, the flowing fluid with high bubble point pressure may exhibit high wellbore storage, as was observed during the testing of the first well. The minimum wellbore storage was achieved by monitoring the well bottomhole pressure and fluid gradient below the tester valve in the same way used for sampling. Prior to shut-in, the well was flowing at drawdown, enough to provide the low noise-to-signal ratio at build-up, and the flow was kept at single phase below the tester valve.

Figure 3 shows the comparison of buildups recorded in 2017 and 2018, where the buildup in 2017 shows large wellbore storage lasting 12 hr vs. 0.3 hr in 2018. The diagnostic plot in 2018 confirmed the heterogeneities in the reservoir, in a time period less than 10 hr, which could potentially be masked by wellbore storage, like in 2017, if the well was not shut-in at the proper flow regime. The build-up could be interpreted as a change of permeability-thickness, correlated with variation shale content laterally. 

The new downhole system recorded the most informative build-up to evaluate the reservoir laterally at certain radius of investigation, which helped to reduce the rig time by avoiding an unnecessarily long build-up recording.  

In 2019, more zones were tested with new, selective firing heads, deployed as part of the live downhole reservoir testing system. To test a zone, the traditional toolstring RIH time is two to three days, and POOH is two days, excluding the time for the test. A multiple zones test requires additional RIH. Moreover, additional RIH may increase the chance of tool failure in an offshore environment with harsh weather conditions. 

Fig. 4. Bottomhole pressure and fluid gradient during reservoir testing with selective perforation.

As a solution to get more information at the same time, Schlumberger ran the new toolstring with two perforation gun systems, Fig. 1. After firing the first gun, the reservoir test was performed for zone one, as per design, and then the second gun was fired and the commingled test of zones one and two was done. Figure 4 shows the bottomhole pressure and downhole fluid gradient during the testing of two zones in a single run, where one can see the activation of the second firing head without using the hydraulic signal. The selective perforation resulted in the necessary information from two zones and saved five days of rig time. 

In summary, the live reservoir testing platform provided flexibility and enabled the ability to acquire high-quality sampling and pressure transient data, and improve the efficiency of well testing operations. 

RESULTS

The reservoir testing campaigns in 2018 and 2019 were completed in an efficient manner, according to the well test program. Throughout the entire job, the live reservoir testing system achieved the following objectives:

• Tests of seven reservoir zones, using selective perforating in the same timeframe that was usually required to test three to four zones.
• Increased operational efficiency by using downhole monitoring to evaluate the effectiveness of wellbore clean-up and controlling the valves independently of annulus commands.
• Gathered more than 30 representative downhole reservoir samples, using downhole monitoring and selective activation of samplers
• Evaluated reservoir parameters and continuity for each reservoir zone within the radius of interest, using real-time data monitoring and interpretation.

CONCLUSION 

The live downhole reservoir testing platform united by wireless telemetry has proven to significantly increase the efficiency and control of offshore well testing operations. This new platform not only reduces rig time and associated costs, which is critical under current market conditions, but it also enables multi-zone dynamic reservoir evaluation for more comprehensive field appraisals and development plans that lead to optimal production.

The deployment of this new reservoir testing platform resulted in Gazprom Neft achieving the required multi-zone tests in the weather-related time window. The platform provided the required dynamic data to de-risk reserves while optimizing the offshore field appraisal program by reducing the number of appraisal wells planned for the future.

^{*Mark of Schlumberger}