Over the course of many years of production, fields that were producing for decades begin to reach mature stages. Most producers at these oilfields have high watercut, and these negative effects the oil production. However, the reason why the wells have a high watercut may not even be related to injectors which cause reservoir flooding, or to bottom-water coning. Typically, the cause of flooding in producers are behind casing and inside casing circulations, tubing leaks, bottom hole leaks, etc., while hydrocarbon reserves around such wells remain unprocessed. After performing water shut-offs on wells with these complications, it is now possible to reduce watercut and also develop poorly drained reserves. The purpose of this paper is to identify "problematic" wells which have high watercut and contain potentially uncovered reserves, which can be fixed by water shut offs to increase recovery factor.

The main objective of the study is to compare the results of the cross-well tracers survey against the pulse code pressure interference testing (PCT) for the complicated geological structures.

The study was based on the numerical simulations on the synthetic 3D models with popular geological complications, such as faults, vertical and horizontal reservoir anisotropy and pinch-outs.

The study has set a special focus on quantitative analysis of the reservoir properties estimated by tracers and PCT as against the known values.

This provides a text-book examples of advantages and disadvantages of both surveillance methods in different geological environment.

Pulse code testing is specific implementation of pressure interference testing by creating a series of injection/production rate changes accordingly to a preset schedule to create a "pressure code" and monitoring the pressure response in the offset wells. The use of high-resolution quarts gauges is highly beneficial in case of large cross-well intervals scanning or poor reservoir quality in case of regular inter-well spacing.

The tracer survey is based on injecting a liquid with chemical markers and subsequent capturing the markers at surface samples in the offset wells. The modern markers are relatively cheap and can be captured at very low concentrations thus making the cross-well scanning available even for high inter-well spacing.

For synthetic models with vertical inhomogeneity the PCT provides a close estimate for compound dynamic reservoir properties (transmissibility and pressure diffusivity).

For synthetic models with lateral inhomogeneity the PCT provides an accurate estimation for effective reservoir thickness and permeability.

Tracers survey is not able to assess the reservoir thickness.

The popular methods to assess reservoir permeability from tracers survey show a substantial deviation from the true reservoir permeability for synthetic models with vertical and lateral heterogeneity.

This leads to conclusion that the most reliable application of racers survey is a qualitative assessment of cross-well connectivity and quantitative estimate of permeability in homogenous reservoirs.

The first study of quantitative comparison of tracer survey against pressure pulse-code interference survey. Tracer survey and PCT efficiency was compared on 3D numerical models. Presence of synthetic models, describing geological complications, which may be seen very often on real reservoirs, provides a reliable basis for comparison.

In order to efficiently asses pressure support during the field development that bears a complex structure of the void space, it is extremely important to understand how existing wells affect each other, this issue was solved at one of the fields in Tatarstan through unique cross-well surveys.

The conventional way to solve the problem of assessing reservoir connectivity consists of analysing seismic surveys, analysing the tectonics and sedimentology at focus region, conducting tracer surveys, interference tests, and production analysis. However, all of aforementioned methods display substantial deficiencies, for instance: poor seismic sensitivity towards low-amplitude faults, poor degree of detail of tectonic analysis, poor tracers representatives in complex vertical and lateral reservoir heterogeneity, if most permeable thin layer lateral anisotropy differs greatly with the main layer anisotropy, huge production losses during interference test along with receiver well shut-ins, and ambiguity in the estimation of interference with the production analysis. That's why is was decided to use pressure Pulse Code Testing (PCT) (Kamal, M. M. 1983; Ahn, S. et al. 2010; Aslanyan, A. et al. 2015; Aslanyan, A. et al. 2016) that managed to overcome those problems and avoid production deferment. The values of reservoir diffusivity and transmissibility are calculated from the recorded in revisers moment of arrival and the amplitude of the pressure disturbance from rate changes in generators. Based on the registered pressure pulse amplitudes we can estimate the influence of generator monthly injection on the pressure at receivers (Myake-shev, N. 2017). The obtained injector influence on producing well is extremely low, and indicates a poor efficiency of pressure maintains system at the tested area. That implicitly indicates on unproductive injection (Zheng, S. 2010).

In addition to a subsequent production logging it was confirmed that there is in fact a presence of a significant amount of unproductive injection due to cross flow downstairs. That was reducing the efficiency of the pressure support in the study area. This placed the start to a set of extended surveys aimed at selecting of the most appropriate injection targets of the injection wells to improve the efficiency of the pressure maintains system as well as oil production increase.

The waterflood performance depends on two major components: the sweep efficiency and displacement efficiency.

The sweep efficiency depends on proper understanding of the vertical and lateral distribution of reservoir properties.

One of the methods to check and calibrate this understanding is to perform pressure interference test (PIT) in few cross-well intervals.

Unfortunately, a proper implementation of traditional step-response PIT with objective for quantitative interpretation requires shutting-down the wells, preferably the whole area around receiving well resulting in punishing production deferment.

This was a bottle-neck for wide spread of quantitative PIT for many decades.

This paper describes the experience with a specific implementation of PIT – Pressure Pulse Code Test (PCT) – which allows data acquisition under scheduled production.

The trade-offs are usually acceptable: longer field operations, high resolution downhole gauges, more complex and longer data processing, advanced software tools and as result – a more expensive service, which anyway comes much cheaper than production deferment.

The paper shows how PCT can be qualified using the synthetic field tests and real field tests and shows a typical application of PCT findings in one of the Eastern Siberian carbonate reservoirs.

The paper is sharing experience on using the cross-well pressure pulse-code testing (PCT) to locate the remaining reserves for the waterflood infill drilling.

R Field is a very mature giant field in Volgo-Ural region of Russia and has been under production for more than 70 years.

One of the key challenges at this stage is to locate the remaining reserves which have been migrating over the field following the waterflood patterns with a lot of areal and vertical flow profile complications.

A waterflood study has been performed on a high viscosity saturated oil deposit with bottom water aquifer and complex geometry driven by regional tectonic stress and numerous shale breaks. The commercial production is on-going for the last 2 years with medium length (1,000 m) horizontal wells and start facing formation pressure decline.

The foremost challenge was to check if injection pressure is transmitted through the oil pay without leaking into the bottom water aquifer. The next question was whether the full net pay is engaged in pressure support under water injection. The last question was to check on permeability anisotropy.

The transmissibility between wells have been assessed with multi-well retrospective testing (MRT) of permanent downhole gauges (PDG) historical data records which are a part of standard ESP telemetry. The fluid mobility and hydrodynamic average thickness between water injector and oil producers have been estimated with cross-well pulse-code pressure pulsations (PCT) based on pre-designed rate variation sequence [1 – 8]. The pulse-code sequence was designed in full-field 3D dynamic model to ensure capturing response in two contrast scenarios: with pressure propagating via aquifer and via oil pay, which have a high degree (30:1) of fluid mobility contrast. The data processing and interpretation was performed in PolyGon™ software [18] using the pulse-code decomposition for PCT tests and multi-well deconvolution for MRT tests.

The cross-well mobility in injector-producer pairs from PCT was indicating that pressure was fairly propagating via oil pay. The effective thickness of PCT-scanned area turned to be in-line with net oil column thickness from 3D geological model.

The MRT-scanned area was showing much lower transmissibility than 3D geological model prediction which was interpreted as the most part of the oil pay in this area has intermittent connectivity due to severe shale breaks development. This gives strong indication on searching the way to commingle production from isolated reservoir elements in this area [8 – 14].

The areal analysis of permeability in PCT-scanned and MRT-scanned areas has indication for 1:2 permeability anisotropy transversal to the regional stress direction which should be reconfirmed by a dedicated study.

The paper describes a practical case of using multi-well pressure Pulse-Code Testing (PCT) for assessment of inter-well connectivity and potential reserves for placement of new wells in off-shore environment. The study was based around two PCT cells (one calibration and one scanning) which were surveyed on the same platform within one month.

The calibration PCT cell was set around injectors in peripheral area to eliminate the uncertainty in reservoir saturation, and provided estimation of macroscopic reservoir permeability (k_a) and macroscopic rock compressibility (c_r) in cross-well intervals. The reservoir permeability was found to be in good correlation with core-calibrated log prediction, while rock compressibility turned out to be twice higher than expected. Additionally, the calibration PCT cell picked the seismic fault as being impermeable and provided accurate values of its proximity to the pulsing well and its extension in the north direction. The sealing nature of this fault explains poor aquifer support in the southwest of the field. The acquired information helped to improve matching of formation pressure in the dynamic model.

The scanning PCT cells identified the baffle in the southern part of the field, which was later interpreted as the bank failure of the meandering river flow. The study concluded that injection in river bedding is detrimental to uniform water flood pattern and should be avoided. The vertical sweep efficiency from PCT study was varying in different directions and helped to calibrate facies distribution and shale breaks. Some wells showed anomalous PCT behavior and were suspected of water production from thief zones, which was later picked by advanced production logging, based on spectral noise logs and temperature modelling.

The fine-grid 3D model was calibrated both on static and dynamic data including the newly acquired framework of PCT and advanced production logging. The analysis of the new model has located the areas of low mobility oil due to poor communication between injectors and producers in these areas. These areas were recommended for infill drilling as well as for rearranging the water injection pattern to improve the sweep and pressure support pattern. The production and water cut of the newly drilled horizontal well showed a good match with the calibrated model prediction.

The key parameters in water flood planning are permeability and formation thickness which define both water front propagation and pressure support.

The fluid flow in low permeability carbonate reservoirs is often happening through micro-fractures which are difficult to capture with cores and when captured are not abundant in statistics and usually not representative for porosity correlation. This leads to difficulties in modelling, forecasting and specifically water-flood planning.

Pressure interference testing is well known approach to capture cross-well permeability and thickness in-situ. But usual well testing procedures require shutting down receiving wells which is punishing for production targets. This well known problem may be addressed with high resolution quartz gauges and pulse-code decomposition mathematics which allow receiving wells to produce normally while recording the pressure data and then decipher the response from a generating well.

This paper demonstrates the practical application of multi-well Pulse Code Testing (PCT) technique for verification of reserves in the vicinity of a horizontal infill well. It also contains an introduction to PCT, where the advantages of this technique over conventional PTA (both single-well and standard multi-well pressure interference testing) are described.

The case study given in this paper deals with the actual implementation of so-called ‘hopper scan’ PCT where a pressure pulse propagates across a row of artificially lifted wells and is then recorded in remote injectors in the next row, thus providing information about a large part of the reservoir without interfering with the production process. The forecast made on the basis of the PCT results was fully confirmed during subsequent hydraulic fracturing operations carried out in the surveyed well, which proved that the PCT information about the reserves was correct.

Three comparatively new technologies have been addressed in this paper:

• Pulse code decomposition aimed at minimising production losses;

• Automated multi-well matching aimed at improving the accuracy of inter-well parameters evaluation;

• ‘Hopper scan’ as a means of minimising the need in workovers and tripping operations in artificially lifted wells.

The paper describes advanced inter-well pressure interference testing used for 3D model calibration accounting for formation layering and rock compressibility in a mature Siberian waterflood field.

The new interference test is based on pulse-code testing (PCT) and can scan inter-well zones without a longterm production shutdown, normally required for conventional pressure interference testing (PIT).

There are numerous applications of this technique but this paper shows only two of them:

• Calibration of a geological model with respect to shale breaks by determining effective formation thickness by PCT and then its correlation with a production flow profile determined by Spectral Noise Logging and temperature modelling

• Determination of rock compressibility distribution throughout a 3D simulation grid by estimating formation compressibility from PCT and correlating it with formation porosity from open-hole logs

The importance of compressibility calibration cannot be overestimated because it defines the formation pressure response to the non-compensated or over-compensated withdrawals across the field and different pay zones.

Conventional PIT can assess formation transmissibility and hydraulic diffusivity between wells. These two properties can be further converted to some basic 3D model inputs, for example effective formation thickness and compressibility, if permeability, SCAL, PVT and formation saturation are known. The main limitation of the conventional PIT is that it requires a receiving well to be shut-in to avoid contamination from production and that the pressure signal should not be contaminated by interference with other wells except the selected pulsing one. This limitation makes conventional PIT impractical for quantitative reservoir characterisation.

PCT generates coded flow-rate pulses in one well and provides a mathematical technique to decode a pressure signal in receiving wells into components from each pulsing well. This allows running PCT in multiple working wells with pre-set rate variation without shutting down production and assessing several inter-well intervals in parallel. A one-month PCT described in this paper resulted in 5% production loss, while conventional PIT would need three months with 60% production loss and a high risk of failure due to pressure contamination from remote processes.

One of the common applications of Pressure Transient Analysis and Pressure Pulse Testing is the evaluation of formation permeability that is referred to as dynamic permeability and is then used to calibrate permeability distribution from a geological model before running full-field flow simulations.

In practice, though, the correlation between permeability from pressure tests and that predicted from open-hole logs is often poor and does not provide consistent calibration because of many factors including poor core data, poor porosity-permeability, complex pressure transient responses and others. In many cases, inaccurate dynamic permeability values are due to misinterpretation of flowing thickness.

In this paper, we demonstrate how Spectral Noise Logging can pick the boundaries of actual flow units and enable the accurate determination of effective thickness to substantially improve the correlation between dynamic and open-hole permeabilities.