Papers

The efficiency of waterflood becomes crucially important when initial reservoir pressure is depleted and the aquifer is proven to be weak. In order to maintain pressure, one must carefully calculate injection / production wells rate, injection targets, define the optimal locations for new injection wells or justify switching producers to water injection. All of these tasks require the cross-well pressure impact data. Paper describes solution of these tasks on a field in Aktobe region, Kazakhstan.

The paper presents a study of a heavy oil mature field in Oman with aggressive water cut growth and slightly exceeding the ultimate recovery as per the initial Master Development Plan expectations. The reserves have been naturally depleted for more than a decade before trying out the waterflood a few years back. The first results of the waterflood were not consistent due to high cross-well interference from one side and possible compartmentalization from another.

The key objective of the current study was to assess the on-going waterflood efficiency, cross-well interference, possible production complications and assess possibility of improving further recovery. The key instrument of the cross-well interference analysis was based on multiwell deconvolution of the permanent downhole pressure gauges in response to the historical flow rate variations in offset wells. The water cut diagnostics was based on the large number of well-by-well metrics including recovery micro-modelling baselines, multiphase IPR analysis and multiphase productivity analysis. The mobile reserves’ potential was assessed through material balance, fractional flow analysis and decline curve analysis. Both watercut diagnostics and reserves evaluation have been facilitated by a digital assistant with a fully automated generator of numerous diagnostic metrics which otherwise would take an unrealistically long time to perform such a study.

The study has come to the conclusion that all wells are fairly connected but confirmed the deterioration of connectivity between a few wells. The water injectors have confirmed a fair connectivity with all surrounding producers while the aquifer was found to be much weaker than the effect from water injection in these wells. The study suggests that this field still contains commercial volumes of hydrocarbon reserves which can be economically recovered, preferably via horizontal side-tracks from existing wells. It has been recommended to repressurize two main reservoir units independently. The study has spotted a few suspects of thief water production and recommended reservoir-orientated production logging to locate the water source, which was most probably occurring behind the casing. These wells have been recommended as primary candidates for side-tracking.

The current study was extensively using a combination of bottomhole pressure deconvolution and advanced watercut diagnostics for heavy oil production to provide a holistic analysis of the remaining reserves. The study also provides the comparison of the results of pressure forecast between multiwell deconvolution technique (MDCV), artificial neural network (ANN) and capacitance-resistivity model (CRM).

Understanding reservoir pressure dynamics and crosswell interference is crucial for optimizing pressure maintenance systems in heterogeneous reservoirs with complex geology. This paper presents a case study from Eastern Siberia, highlighting the positive impact of applying Multi-Well Retrospective Test (MRT) machine learning technology on production enhancement.

MRT technology relies on mathematical algorithms for annualizing long-term records of bottomhole pressure and surface rates from a group of wells through multiwell deconvolution. It requires historical data of bottomhole pressures for the tested well and flow rate history for all wells under study. Multiwell deconvolution involves a fully or semi-automated search for initial pressure and Unit-rate Transient Response (UTR) for tested wells and cross-well intervals, aligning actual pressure records with total sandface flow rate variation history. It also quantifies the accumulated pressure impact of surrounding wells on the tested well.

The study area featured nine wells with declining production rates, including six producers and three injectors. The primary objective was to assess production enhancement potential, primarily through injection optimization. The seven-year dataset encompassed flow rate and pressure variations during production. Before employing machine learning, data were preprocessed to reduce the number of analysis points, synchronize flow rate and pressure change timings, and remove outliers. Mathematical deconvolution procedures were then applied to derive UTRs, with UTR convolution providing crosswell pressure impact. Two injection wells were found to have a significant cumulative pressure impact on production wells. Mathematical well shut-ins yielded reservoir pressure and well productivity index. UTR interpretation via pressure transient analysis algorithms offered insights into reservoir transmissibility, well skin, and interference-free drainage areas. Machine learning algorithms generated pressure/rate forecasts for different well targets, indicating that the optimal production increase could be achieved through a 1.5x increase in injection rate for one well and a 2.7x increase for another well, resulting in a twofold oil production increase with constant water cut.

Field implementation demonstrated that MRT technology is a powerful tool for optimizing injection targets and increasing oil production. Additionally, MRT provides reservoir pressure data without well shut-ins, enabling the operator company to gather information for reservoir pressure mapping without production deferment, resulting in a significant increase in Net Present Value (NPV).

An off-shore field in SE-Asia has high reservoir heterogeneity and consists of several highly permeable layers. The current field development challenges are to evaluate the potential for additional drilling and reveal the potential of production increase by injection optimization. Good Understanding of cross-well reservoir connectivity at the area, the shape and size of existing wells drainage area, reservoir properties distribution and cross-well pressure impacts are the key points for additional drilling projects and production enhancement.

A1 reservoir in this field was at the focus of the study. This reservoir produces light oil and with the decrease in formation pressure, gas production has increased. A Multi-well Retrospective Testing (MRT) service was applied based on historical well pressure and production data to evaluate the reservoir compartmentalization, quantify well interference and drainage area. Historical data over 12 years (2007 to 2019), from an area consisting of 4 producers and 1 injector was analyzed using MRT. MRT extends the technique of single-well deconvolution to the analysis of pressure and production data to a group of wells. MRT was used to evaluate reservoir transmissibility between wells, cross-well interference, formation pressure history, productivity index dynamics and well drainage area. The deconvolved single unit-rate pressure drawdown transient recovered by multiwell deconvolution was interpreted to calculate formation properties around the pressure-tested well (self-transient response) and cross-well properties between offset wells (interference test response). This self-transient response is free of interference from dynamic boundaries of surrounding wells. Its interpretation by pressure transient analysis provided well drainage area, shape and aquifer/gas cap support for the well. Cross-well pressure transient responses revealed reservoir transmissibility between wells. MRT analysis found that all the offset wells were connected to the focus well. the reservoir transmissibility of the connected part of the formation between the wells was lower than expectations from open hole logs.

MRT revealed weak pressure support from the aquifer and gas cap, that was insufficient to compensate field pressure for current throughputs. A formation pressure depletion trend was calculated resulting in gas liberation. However, the well drainage area was found to be extensive than expected. This could indicate a possible reservoir extension perhaps in the north-east direction. Further Geological and geophysical studies are required to address the uncertainties in the area.

The results of the MRT study were used as inputs for numerical cross-well pressure modeling and then translated to conventional reservoir modeling language, to try to obtain a better understanding of MRT measured reservoir properties. he information from MRT study as used to optimize upcoming infill locations and other opportunities for production enhancement: well stimulation and injection increase.

The paper provides introduction into the mathematical aspects of Multiwell Deconvolution (MDCV) and Capacitance Resistance Model (CRM) and connection between them. Both methods are trying to train a model over the long-term history of surface flowrates and bottomhole pressure readings and then predict bottomhole and formation pressure in response to a given production/injection flowrate scenario (called "rate control simulation") or alternatively may predict flowrate and formation pressure in response to a given bottomhole pressure scenario (called "pressure control simulation"). It has been shown that CRM can be viewed as a partial case of MDCV with a specific type of a drawdown and cross-well pressure transient responses which is not always met in practice. The paper also explains limitations which are common for both methods and specify additional limitations of CRM which MDCV can handle.

The analyzed oi- gas field is based around Orenburg region, located 40 km away from the Buzuluk city, Russia.

This multi-layered field has a number of domes. 11 productive layers lie within its cross-section. In total, 21 oil and two gas deposits have been identified at this field.

The study layer A4 is confined to the top of the Bashkir layer and has a wide extension. Permeable rocks at this layer include limestone and dolomite, separated by impermeable sublayers. The effective oil-saturated well thicknesses vary between 1.1-38.4 m, and is 11.8 m on average. The caprock of the formation A4 consists of the Vereiskan clay-siltstone sequence.

The study field is located in the Nizhnevartovsk district of the Khanty-Mansi autonomous region. The deposit is located in the Nizhnevartovsk crest zone. The geological section of this deposit features a thick layer (2740-2870 meters) of Meso-Cenozoic era sedimentary rocks starting from the Jurassic period up to and including the Quaternary period, and rests unconformably on the surface of the deposits of the folded Paleozoic basement. The pay zones of study oil and gas fields features mainly sandstone-siltstone reservoirs.

The study formation XX11-2 features interleaved rocks with a high clay content. In the west and south-west of the field, the oil-saturated thicknesses vary on average from 5-10 m, and in the north, the thickness increases to 10-20 m.

The main goal of the pilot job is to assess the risks of production by horizontal wells and multilateral wells with a close gas cap above and water layers beneath the main formation. The objectives are to monitor the total producing length of the wells using temperature and pressure surveillance. The results of monitoring were analyzed at different stages of development.

An analysis was carried out by combining pressure and temperature data obtained while monitoring the production of multilateral wells. The well properties were determined using RTA and PTA.

To assess the inflow profile, distributed temperature sensors in the wells were analyzed for the entire period of appraisal production. A feature of the research was the low contrast of temperature anomalies associated with fluid inflow. In addition, it was also revealed that the DTS absolute readings at the depth of the formation were affected by surface temperature, which required corrections and the use of relative readings in the calculations instead of absolute ones.

The main feature of the pressure analysis was the short period of production. With such well completion geometry and reservoir properties of the layer, the radial flow could not be achieved during the whole test period. Despite these limitations, the dynamics of the total producing length of the well was determined. The initial value of the producing length was about 70% of the drilled length, then there is a slight decrease after 7 to 10 months of well production.

By analyzing the fiber-optic temperature profile, an inflow profile was assessed. Based on the analysis of changes in relative temperature anomalies, the shares of inflow from the sidetracks were estimated.

Several memory temperature / pressure gauges set along the horizontal section were used as an additional data source to monitor well parameters during the whole period of production. The difference in their readings was due to, among other things, the average flow rate in the section between the sensors, which made it possible to give an independent assessment of the inflow profile.

Based on the results of the job performed, a number of risks and uncertainties were removed, including information on the total flowing horizontal length dynamics, which is a valuable input for full-field development planning. In addition, an express method of DTS data analysis has been developed for assessing the wellbore producing length without significant temperature changes associated with intervals of inflow.

Target reservoir and production characterization study was carried out in Pematang Lantih field, Jambi, Indonesia. The Talang Akar Formation has 10 underlying reservoirs from 600 m to 900m TVDSS. This multi-layers sandstone structure is driven by regional tectonic stress and complicated by several faults. Sharp oil well production decline was observed during 3 years period since initial production in 2015, with GOR increase. Arresting production decline was the key objective for efficiency increase, hence improved reservoir characterization was needed, as cross-well reservoir properties/interference were unclear. Multiwell Retrospective Test (MRT) is a recent development used to study reservoirs by carrying out automatic matching of historical production rates and bottom hole. It provides practical, fast yet robust analysis for reservoir evaluation. It can quantify inter-well pressure interference and evaluate cross-well reservoir properties. The main goal of this study was to get better reservoir understanding and evaluate ability of this technique to deliver additional value at current reservoir conditions, considering initial data availability/quality.

The key technology element used is multi-well pressure deconvolution, which is a highly parallelizable decoding algorithm running on multi-core workstation. The analysis is carried out on historical well pressure and production data. Hence no field operation is needed and there is no production deferment since it does not require additional field data acquisition. The technique delivers formation pressure history and productivity index history in tested well reconstruction. It is also proficient to reconstruct cross-well interference and estimate cross-well transmissibility from offset wells towards the tested well. Another result is evaluation of formation pressure decline impact on oil production of the existing wells.

The study area has reservoir pressure that dropped below bubble point and continues declining. Historical data over 3 years, from a cell consisting of 4 producers was analyzed using this technique. The analysis found uniform formation transmissibility between the analyzed wells at Pematang Lantih field. Transmissibility was estimated by analyzing cross-well transient responses (CTR) calculated with multi-well deconvolution. CTR is a function representing BHP response to neighbor well single rate production. CTR is interpreted with interference test technique thus estimating transmissibility values.

The analysis result confirmed that all 3 offset wells have a pressure impact towards the pressure-tested well (PLT-X) with quantified values. Connectivity analysis showed the expectation of rapid production decline if there was no pressure maintenance system. The recommendation was to estimate the economics of pressure maintenance system implementation in order to improve production performance.

By using multi-well deconvolution analysis, the entire 3-years cell production history was converted into a single unit-rate pressure transient that enabled deep reservoir investigation and calculation of field reserves undisturbed by dynamic well boundaries.

The study field consists of four oil pays and is currently going through a waterflood trial.

Due to a presence of high amplitude faulting it becomes crucially important to understand the geology of the field and reservoir connectivity prior to progressing the waterflood project.

The results of the cross-well tracers have indication (some strong and some vague) of communication between a trial water injector and all oil producers in the same and adjacent compartment.

Since the wells were equipped with permanent downhole pressure gauges it was possible to decipher the cross-well communication using the Multiwell Retrospective Testing (MRT) technique based on multiwell deconvolution algorithm (MDCV).

The results of MRT study were showing no traceable communication between trial water injector and offset wells in adjacent compartment except one producer which showed a strong response across the fault.

By correlating the MRT results with seismic profile and well completion it became possible to establish how exactly the main pay is communicating between the compartments.

It also carried few learning points on how to interpret results of cross-well tracers and MRT in terms of reservoir properties.

The investigated field is located in the Solikamsk drawdown in the northeast of the Perm Territory. The oil content level of this field is composed of Tournaisian-Famennian, Radaevsky, Radaevian, and Tula formations. This article will analysis carbonate deposits from the Tula formation using the multiwell retrospective testing (MRT) technology.

Currently, the development system has been already formed, and there is ongoing compaction drilling and targeted drawdown increase that is carried out at certain wells. A pressure support system has been formed. Before the surveys have been conducted, there was a trend in production decline, for reasons that are currently unknown. To identify the causes of production decline at the carbonate reservoir in the field, special technology was used to analysis production history data and bottom hole pressure - this technology is called multiwell retrospective testing (MRT).

Four sections were selected for further analysis, MRT was able to reconstruct the reservoir pressure variations and production coefficient at the tested well, the influence of the offset wells on the tested wells has been evaluated, along with transmissibility at the cross-well interval and well-bore skin of the tested wells.

The massive industry digitalization creates huge data banks which require dedicated data processing techniques.

A good example of such a massive data bank is the long-term pressure records of Permanent Downhole Gauges (PDG) which became very popular in the last 20 years and currently cover thousands of wells in Company RN.

Many data processing techniques have been applied to interpret the PDG data, both single-well (IPR, RTA[1]) and multi-well (CRM [2] - [5] and various statistical correlation models).

The ability of any methodology to predict the pressure response to rate variations and/or rate response to pressure variations can be easily tested via numerical modelling of synthetic fields or via comparison with the actual field production history.

This paper presents a Multi-well Retrospective Testing (MRT, see  Appendix A and [6] - [9]) methodology of PDG data analysis which is based on the Multi-well Deconvolution (MDCV, see  Appendix B and [10] - [20]) and the results of its blind testing against synthetic and real fields.

The key idea of the MDCV is to find a reference transient pressure response (called UTR) to the unit-rate production in the same well (specifically called DTR) or offset wells (specifically called CTR) and then use convolution to predict pressure response to arbitrary rate history with an account of cross-well interference.

The MRT analysis is using the reconstructed UTRs (DTRs and CTRs) to predict the pressure/rates and reconstruct the past formation pressure history, productivity index history, cross-well interference history and reservoir properties like potential and dynamic drainage volumes and transmissibility.

The results of the MRT blind testing have concluded that MRT could be recommended as an efficient tool to estimate the current and predict the future formation pressure without production deferment caused by temporary shut-down for pressure build up. It showed the ability to accurately reconstruct the past formation pressure history and productivity index. It also reconstructs the well-by-well cross-well interference and reservoir properties around and between the wells.

The blind-test also revealed limitations of the method and the way to diagnose the trust of the MRT predictions.

Engineers are now considering using MRT in Company RN as a part of the selection/justification package for the new wells drilling, conversions, workovers, production optimization and selection of surveillance candidates.

In case of brown fields and fields currently undergoing drilling, it is highly important to revise field geology to effectively design pressure support and further refine the existing pressure maintenance system if required. At the same time, the analysis of cross-well interference using Multiwell Retrospective Testing (MRT) is very useful for assessing its effectiveness, and is the main tool, that was used at one of the fields in Tatarstan Republic.

Conventionally to identify the geological structure and assess the reservoir connectivity it is required to use tools that could be quite costly, require expensive field operations and take up a lot of time. These tools include seismic surveys, paleotectonic analysis of the survey zone, tracer surveys and interference tests. Each of these methods comes with well-known disadvantages: weak seismic sensitivity to low-amplitude faults, poor resolution of tectonic analysis, long duration of tracer surveys and their low performance against man-made fractures and inconsistent extension in lateral anisotropy of the reservoir, huge production losses during interference tests due to receiving well shut-ins. In this regard, the MRT technology was chosen as the main tool for assessing pressure support at the brown field. This technology is fully fledged and is currently being implemented at a large-scale, having passed the testing stage on both synthetic and actual fields (Aslanyan, 2019) (Aibazarov, 2019) (Ganiev, 2019) (Kovalenko, 2018) (Krichevsky, 2017). Based on previously collected bottom-hole pressure readings registered during the well production and on production history of a set of analysed wells, the of cross-well interference was restored using multi-well deconvolution algorithms as well as proposals for production increase.

In accordance with the conducted surveys, the reservoir geology was refined, inefficient injectors in terms of pressure support was identified, and it was advised to redistribute the injection to balance it out that will ultimately lead to production increase.

Well spacing optimization is very important at the stage of drilling the reservoir. It is critical for the whole project economics. After the reservoir is already drilled it is very important to understand does existing wells drain all the reserves of infill drilling requires to improve recovery. Such task was solved on a tested area - Western part of Karachaganak gas condensate field. It has a complex geology, built as a massive heterogeneous carbonate reef of a Carboniferous age. PVT properties of the reservoir fluid significantly varies with depth. The area is produced with horizontal wells to maximize contact with the reservoir.

The Multi-well Retrospective Testing (MRT) on base of multi-well deconvolution of historical rate and bottom-hole revealed well drainage area and well interference (1 – Aslanyan, 2018; 2 – Aslanyan 2017, 3 – Aslanyan 2019). The MRT study is showing a strong pressure depletion trend and a fair connection between wells in the certain areas like core of western build up.

The paper describes the first use of Multiwell Retrospective Test (MRT) on the Devonian formation of the Romashkinskoye oil field.

The paper introduces the technology of MRT and describes the advantages in determining the interference of wells and formation pressure (4-7).

The field case cited in the article describes a specific implementation of an MRT, called "radial deconvolution," in which the central (tested) well is equipped with a bottomhole pressure gauge. As a result, the interference of the offset injection and production wells to the tested well is estimated, as well as the properties of the well and reservoir, taking into account the interference with the offset wells. One of the advantages of this technology is the ability to estimate formation pressure without shutting the well. In this research, a comparative test was performed, in which the reservoir pressure predicted by MRT was checked with a field test.

A waterflood study has been performed on a heterogeneous oil deposit with a rising water-cut and production decline after 10 years of commercial production.

The objective was to analyze the efficiency of waterflood patterns across the field and suggest injection optimization opportunities.

The production is facilitated by ESP with Permanent Downhole Gauges (PDGs) which provides an opportunity to analyze the productivity index and cross-well interference.

The PDG analyzes was performed in PolyGon pressure modelling facility and followed Multi-well Retrospective Testing (MRT) workflow which is based on the mathematical procedure of multiwell deconvolution (MDCV).

MDCV trains the correlation between bottom-hole pressure (BHP) variations from PDG data records and rates variations from daily production history of a given well and other wells around it.

This provides a robust short-term predictor for production response for different rate/BHP scenarios and makes a basis for injection optimization opportunities.

MDCV allows reconstructing formation pressure and productivity index back in time, pick up the changes and understand if they were caused locally (by skin) or massively (by transmissibility).

The diffusion modelling of deconvolved data allows a robust quantification of some reservoir properties in cross-well intervals, such as the current drained volume around each well, potential drained volume (as if the offset wells are shut-down), apparent cross-well transmissibility, boundary types and compare them against the various geological scenarios and possible well-reservoir contact scenarios.

The quantitative analysis allows picking up anomalously high cross-well interference which may be caused by thin-bedding circuiting or induced fracture. It also provides a strong hint for thief-injection and thief-production in cases of poor cross-well interference.

A sandstone formation is showing accelerated production decline during the fully compensated waterflood development. The sporadic well tests suggested that liquid rate was following the non-uniform formation pressure decline, despite the full compensation of the offtakes. The paper presents a multiwell downhole pressure gauge deconvolution technique and associated study on the reasons of non-uniform area formation pressure decline and non-uniform injection water front propagation and resulted in recommendations which proved their efficiency after implementation.

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.

This work is dedicated to the creation of complex methods of determining reservoir properties in injection wells with injection-induced fractures by production logging tests (PLT) and well testing.

During exploitation, injection wells are known to create uncontrolled fractures so called injection-induced fractures. They appear when the injection pressure exceeds formation tensile strength. They can spread both in height and length, depending on the injection rate.

The risks of fractures inducing during work are especially great in tight formations. They influence oil field development negatively because their growth in height can connect additional layers that change the distribution of water injection in layers.

Complex analysis of PLT and well testing during step-rate injection tests and shut in provides the opportunity not only to determine fracture properties, but also to estimate parameters of layers connected by injection-induced fracture. Series of different injection pressure tests and a fall-off are suggested to perform this task. Suggested interpretation method is based on the fact, that the size of fracture changes with different injection pressure, connecting more or less layers. Joint analysis of well tests and PLTs helps to diagnose and estimate the number of these changes.

In the paper, it is shown that the results of the interpretation of measurements of permanent reference gages on the electric submersible pump (ESP) together with the data on the change in the historical production rate of the wells allow carrying out the justification and support of the oil production enhancement operations and also the analysis of the efficiency of the oil production enhancement operations performed by estimating the current skin-factor of the wells and reservoir pressure. In particular, wells have been identified in which worsening of the skin-factor in time is observed. For them, the optimal time for performing repeated well interventions was chosen to improve the skin-factor and increase production from the wells.

Separate results of the work are represented by an express method for selecting the optimal time for transferring production wells to injectors for pressure maintains to optimize the production of a section of the oilfield based on the telemetry gages on the ESP. At the same time, the forecasts were made on the basis of express 2D models in the software "Topaze", which significantly increases the speed of work execution compared to full 3D modeling, and the accuracy of forecasts remains quite high.

The paper shows that the results of the historical flow rate of wells and the telemetry of pumps are a good informational basis for the application of a new method for analyzing cross-wellbore interference – multi-well deconvolution (MWD).

Thus, without a loss of production, a analysis of the results of a production decline was carried out on the basis of the algorithms for interpretation of the well test and recommendations of production enhancement operations were justified to increase production.

To discover remained reserves and recommend production enhancement operations in a carbonate reservoir with long production history it is important to perform not only production analysis, water breakthrough areas, but also areas, that took a lot of injected water during injection history. It's not an easy task in case of complicated formation pore structure especially than injection were carried on with high pressures and overbalancing.

Combined approach was used for remained reserves localization and production enhancement operations. It included complex geology study, production history and surveillance data. Well interference was examined by novel technology - multi-well deconvolution (MWD).

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.

The paper presents the results of a study project of 60+ well block of the large (> 1,000 wells) mature (30 year old) oilfield in Western Siberia with objective to localise and characterize residual recoverable reserves and propose the optimal economic scenario for further depletion.

Low permeability, heterogeneous reserve structure along the cross-section, numerous induced hydraulic fractures in producing wells and numerous spontaneous fractures in injecting wells with dynamic behavior, aggravated by numerous behind-the-casing crossflows in almost every well have resulted in a very complex conditions of remaining reserves.

The conventional methods of production analysis and surveillance (well testing and production logging) do not provide a consistent picture of the current distribution and conditions of the remaining reserves and required a deeper and more complex analysis.

Development Opportunities Management workflow was chosen for this particular holistic study, which includes a set of interconnected studies, field surveillance, geological and flow modelling and culminated in field development planning based on the digital asset twin. (Ganiev, B., 2021)

Digital asset twin was constructed based on results of this workflow with a full-range economical model, flow simulation over the thoroughly calibrated fine-grid 3D dynamic model and production complication model (dynamic behavior of the fractures and behind-casing channeling).

The 3D model has been calibrated on results of the cross-well pressure-pulse surveillance, reservoiroriented production logging and was validated by the results of the drilling of the transition wells.

The digital asset twin was used to find the optimal investment scenario based on multivariate calculations with the help of digital assistants.

Due to simplicity of the user interface and client-server design, the digital twin was made available for various corporate engineers and managers without any modelling skills to play around with their own ideas on possible production/investment scenarios which gave another level of validation of the ultimate field development plan.

All activities carried out within the digital twin automatically generate a complete package of investment metrics(NPV, PI, IRR, MIRR, Cash Flow and many correlation graphs) to assessthe economic efficiency of each package and select the most appropriate solution for further ultimate choice.

The approved scenario was based around drilling 6 producing side-tracks in specific locations/trajectories, performing workovers on specific offset injectors and re-scheduling of the production/injection rates in all block wells.

The results of the field development’s activities implementation will be the subject of a future publication.

The residual reserves localization and geology specification for oil recovery increase by production enhancement operations play main role for brown fields with production decline. The set of solutions includes targeted recommendations for additional well surveys followed by workovers in production and injection wells, whole wellbore or selective stimulation, hydraulic fracturing and side tracking. As a result, previously poorly drained areas are involved in production, which increases the current rates and the final oil recovery.

The integrated technology of residual reserves localization and production increase includes:

1. Primary analysis of the production history for blocks ranking by production increase potential.
2. Bottom-hole pressures and production history advanced analysis my multi-well deconvolution for pressure maintenance system optimization and production enhancement.
3. Advanced production logging for flow profile and rate layer-by-layer allocation
4. Conducting pulse-code interference testing for average saturation estimation
5. 3D reservoir dynamic model calibration on tests findings
6. Multi-scenario development planning for the biggest NPV scenario regarding surface infrastructure

The presented integrated technology consists of several stages. The results of the first stage allow for a toplevel assessment of the current development opportunities of the area, evaluate current residual reserves (estimate displacement factor, assess conformance factor), as well as the available production increase potential for various blocks of the studied field.

Results of the second stage carried out on the block with the maximum potential allow identifying problems and offer solutions and the necessary set of studies for localization of current reserves. For the purpose an advanced logging and testing operations are used, which includes both single-well and multi-well studies.

Pulse-code interference tests, multi-well retrospective tests and reservoir-oriented production logging make it possible to scan the reservoir laterally and vertically, which is especially important for multi-layer fields.

The reservoir parameters from the test results are used to calibrate dynamic reservoir model. The effects of production enhancement operations are calculated on 3D model. The set of possible activities is evaluated in terms of their financial efficiency based on the economic model of the operator company by multiscenario approach.

The uniqueness and novelty of this approach consist of integrated usage of advanced production logging and well-testing technologies, as well as further calibration of the dynamic reservoir model on test results.

Paper presents how to apply the test results for the reservoir model calibration and increase forecast reliability by reducing the model ambiguity, how brown field profit increase.

The petroleum industry maintains a keen interest in asset assessment tools. This paper presents a practical case study involving high-level geological and dynamic data analysis to evaluate petroleum asset potential for further investment aimed at optimizing secondary recovery. The economic model, grounded in the balanced waterflood flow approach, determines the optimal injection volumes and the associated number of oil-producing and water-injecting wells.

Analyzing production data is complex, relying on numerous diagnostic metrics such as reserve properties analysis, reservoir energy diagnostics and watercut/GOR diagnostics, productivity measures, and economic factors. This analysis facilitates rapid modeling of future performance and forecasts economic outcomes in response to redevelopment investments.

Automation has revolutionized modern production analysis, enabling the generation of comprehensive diagnostic metrics with a simple "mouse click"—a process that typically spans months. Newly developed diagnostic metrics improve upon traditional production/injection performance analysis, especially those based on automatically generated numerical 3D micro-models that simulate expected rock/fluid properties.

Well interference is assessed through mathematical algorithms for multiwell deconvolution, utilizing extensive bottomhole pressure and surface rate data. This deconvolution, either fully or semi-automated, searches for initial pressure and unit-rate transient responses in tested and adjacent wells, aligning them with actual pressure records and aggregate flow rates.

Further advancements include the automated analysis of these diagnostic metrics, supported by AI-based digital tools that offer economic insights for enhancing production.

The case study in Western Siberia identifies deposits and wells where not all proven recoverable reserves are being tapped. It advocates for side-tracking from current wells and implementing multi-stage fracking to activate these reserves and sustain pressure. The economic model generated by this study proposes investment scenarios with a profitability index (PI) of 1.4, an attractive prospect considering the reserves’ current maturity.

The application of deconvolution in cross-well pressure interference analysis has fine-tuned production and water injection targets, yielding a 6% uplift in field oil production without the need for well interventions.

This paper presents a couple of examples of waterflooding efficiency assessment and a ranked list of investment opportunities to unlock field potential. Integrating open-hole data with meticulous well-by-well production analysis, we pinpoint prospective drilling sites. Advanced production analysis notably accelerates the analysis process, thereby diminishing the risk of overlooking enhancement opportunities.

The paper presents a study of a heavy oil mature field in Oman with aggressive water cut growth and slightly exceeding the ultimate recovery as per the initial Master Development Plan expectations. The reserves have been naturally depleted for more than a decade before trying out the waterflood a few years back. The first results of the waterflood were not consistent due to high cross-well interference from one side and possible compartmentalization from another.

The key objective of the current study was to assess the on-going waterflood efficiency, cross-well interference, possible production complications and assess possibility of improving further recovery. The key instrument of the cross-well interference analysis was based on multiwell deconvolution of the permanent downhole pressure gauges in response to the historical flow rate variations in offset wells. The water cut diagnostics was based on the large number of well-by-well metrics including recovery micro-modelling baselines, multiphase IPR analysis and multiphase productivity analysis. The mobile reserves’ potential was assessed through material balance, fractional flow analysis and decline curve analysis. Both watercut diagnostics and reserves evaluation have been facilitated by a digital assistant with a fully automated generator of numerous diagnostic metrics which otherwise would take an unrealistically long time to perform such a study.

The study has come to the conclusion that all wells are fairly connected but confirmed the deterioration of connectivity between a few wells. The water injectors have confirmed a fair connectivity with all surrounding producers while the aquifer was found to be much weaker than the effect from water injection in these wells. The study suggests that this field still contains commercial volumes of hydrocarbon reserves which can be economically recovered, preferably via horizontal side-tracks from existing wells. It has been recommended to repressurize two main reservoir units independently. The study has spotted a few suspects of thief water production and recommended reservoir-orientated production logging to locate the water source, which was most probably occurring behind the casing. These wells have been recommended as primary candidates for side-tracking.

The current study was extensively using a combination of bottomhole pressure deconvolution and advanced watercut diagnostics for heavy oil production to provide a holistic analysis of the remaining reserves. The study also provides the comparison of the results of pressure forecast between multiwell deconvolution technique (MDCV), artificial neural network (ANN) and capacitance-resistivity model (CRM).

The paper shares a practical case of production analysis of mature field in Western Siberia with a large stock of wells (> 1,000) and ongoing waterflood project.

The main production complications of this field are the thief water production, thief water injection and non-uniform vertical sweep profile.

The objective of the study was to analyse the 30-year history of development using conventional production and surveillance data, identify the suspects of thief water production and thief water injection and check the uniformity of the vertical flow profile.

Performing such an analysis on well-by-well basis is a big challenge and requires a systematic approach and substantial automation.

The majority of conventional diagnostic metrics fail to identify the origin of production complications. The choice was made in favour of production analysis workflow based on PRIME metrics, which automatically generates numerous conventional production performance metrics (including the reallocated production maps and cross-sections) and additionally generates advanced metrics based on automated 3D micro-modelling.

This allowed to zoom on the wells with potential complications and understand their production/recovery potential.

The PRIME analysis has also helped to identify the wells and areas which potentially may hold recoverable reserves and may benefit from additional well and cross-well surveillance.

The paper presents the results of a study project of 60+ well block of the large (> 1,000 wells) mature (30 year old) oilfield in Western Siberia with objective to localise and characterize residual recoverable reserves and propose the optimal economic scenario for further depletion.

Low permeability, heterogeneous reserve structure along the cross-section, numerous induced hydraulic fractures in producing wells and numerous spontaneous fractures in injecting wells with dynamic behavior, aggravated by numerous behind-the-casing crossflows in almost every well have resulted in a very complex conditions of remaining reserves.

The conventional methods of production analysis and surveillance (well testing and production logging) do not provide a consistent picture of the current distribution and conditions of the remaining reserves and required a deeper and more complex analysis.

Development Opportunities Management workflow was chosen for this particular holistic study, which includes a set of interconnected studies, field surveillance, geological and flow modelling and culminated in field development planning based on the digital asset twin. (Ganiev, B., 2021)

Digital asset twin was constructed based on results of this workflow with a full-range economical model, flow simulation over the thoroughly calibrated fine-grid 3D dynamic model and production complication model (dynamic behavior of the fractures and behind-casing channeling).

The 3D model has been calibrated on results of the cross-well pressure-pulse surveillance, reservoir-oriented production logging and was validated by the results of the drilling of the transition wells.

The digital asset twin was used to find the optimal investment scenario based on multivariate calculations with the help of digital assistants.

Due to simplicity of the user interface and client-server design, the digital twin was made available for various corporate engineers and managers without any modelling skills to play around with their own ideas on possible production/investment scenarios which gave another level of validation of the ultimate field development plan.

All activities carried out within the digital twin automatically generate a complete package of investment metrics (NPV, PI, IRR, MIRR, Cash Flow and many correlation graphs) to assess the economic efficiency of each package and select the most appropriate solution for further ultimate choice.

The approved scenario was based around drilling 6 producing side-tracks in specific locations/trajectories, performing workovers on specific offset injectors and re-scheduling of the production/injection rates in all block wells.

The results of the field development's activities implementation will be the subject of a future publication.

The paper presents a practical case of production performance analysis at one of the mature waterflood oil fields located at the Volga-Ural oil basin with a large number of wells. It is a big challenge to analyse such a large production history and requires a systematic approach.

The main production complication is quite common for mature waterflood projects and includes non-uniform sweep, complicated by thief injection and thief water production. The main challenge is to locate the misperforming wells and address their complications.

With the particular asset, the conventional single production analysis techniques (oil production trend, watercut trend, reservoir and bottom-hole pressure trend, productivity trend, conventional pressure build-up surveys and production logging) in the vast majority of cases were not capable of qualifying the well performance and assessing of remaining reserves status. The performance analysis of such an asset should be enhanced with new diagnostic tools and modern methods of data integration.

The current study has made a choice in favor of using a PRIME analysis which is multi-parametric analytical workflow based on a set of conventional and non-conventional diagnostic metrics. The most effective diagnostics in this study have happened to be those are based on 3D dynamic micro-models, which are auto-generated from the reservoir data logs.

PRIME also provided useful insights on well performance, formation properties and the current conditions of drained reserves which helped to select the candidates for infill drilling, pressure maintenance, workovers, production target adjustments and additional surveillance.

The paper illustrates the entire PRIME workflow, starting from the top-level field data analysis, all the way to generating a summary table containing well diagnostics, justifications and recommendations.

This paper presents a practical case of Field Development Planning (FDP) process with extensive use of petroleum asset digital twin facilities. The paper explains the process of setting up both the digital twin and the performance metrics which were used to steer the multivariate trials on redevelopment activities towards the optimal investment scenario.

The petroleum asset is represented by a block of the large oilfield in Western Siberia with ongoing waterflood project at mature stage.

The process of building FDP was performed through a series of interactive sessions with the petroleum asset digital twin which includes three major group of functionalities:

• Convert redevelopment activities (drilling, workovers, production optimization and surface facilities) into the production response and basic investment indicators including NPV, PI, IRR, MIRR, ROI

• Provide technical performance metrics (such as formation pressure, watercut and recovery responses, potential case of integrity failures, behind casing channelings, spontaneous formation fracturing, surface pipeline pressure losses) that can help understand the results of the FDP activities

• Provide well and cross-well surveillance simulations (pressure tests, production and integrity logging) to help identify the candidates for future monitoring.

Two different multidisciplinary teams undertook 12 FDP iterations over two different 3D full-field model realizations to arrive at the best investment scenarios for each model.

After that the FDP team has picked up the best practices from both FDPs in the form of those field development actions which turned to be financially successful in both model realizations. All those cases were prioritized and merged into the ultimate FDP scenario and verified across both digital asset realizations.

The new FDP suggested the new drilling opportunities, few integrity workovers, few conversions and a new production target strategy for producers and injectors. Apart from investment benefits, the new FDP provides substantial accelerated oil withdrawals and increase in ultimate recovery comparing to the no-future-activity scenario.

An off-shore field in SE-Asia has high reservoir heterogeneity and consists of several highly permeable layers. The current field development challenges are to evaluate the potential for additional drilling and reveal the potential of production increase by injection optimization. Good Understanding of cross-well reservoir connectivity at the area, the shape and size of existing wells drainage area, reservoir properties distribution and cross-well pressure impacts are the key points for additional drilling projects and production enhancement.

A1 reservoir in this field was at the focus of the study. This reservoir produces light oil and with the decrease in formation pressure, gas production has increased. A Multi-well Retrospective Testing (MRT) service was applied based on historical well pressure and production data to evaluate the reservoir compartmentalization, quantify well interference and drainage area. Historical data over 12 years (2007 to 2019), from an area consisting of 4 producers and 1 injector was analyzed using MRT. MRT extends the technique of single-well deconvolution to the analysis of pressure and production data to a group of wells. MRT was used to evaluate reservoir transmissibility between wells, cross-well interference, formation pressure history, productivity index dynamics and well drainage area. The deconvolved single unit-rate pressure drawdown transient recovered by multiwell deconvolution was interpreted to calculate formation properties around the pressure-tested well (self-transient response) and cross-well properties between offset wells (interference test response). This self-transient response is free of interference from dynamic boundaries of surrounding wells. Its interpretation by pressure transient analysis provided well drainage area, shape and aquifer/gas cap support for the well. Cross-well pressure transient responses revealed reservoir transmissibility between wells. MRT analysis found that all the offset wells were connected to the focus well. the reservoir transmissibility of the connected part of the formation between the wells was lower than expectations from open hole logs.

MRT revealed weak pressure support from the aquifer and gas cap, that was insufficient to compensate field pressure for current throughputs. A formation pressure depletion trend was calculated resulting in gas liberation. However, the well drainage area was found to be extensive than expected. This could indicate a possible reservoir extension perhaps in the north-east direction. Further Geological and geophysical studies are required to address the uncertainties in the area.

The results of the MRT study were used as inputs for numerical cross-well pressure modeling and then translated to conventional reservoir modeling language, to try to obtain a better understanding of MRT measured reservoir properties. he information from MRT study as used to optimize upcoming infill locations and other opportunities for production enhancement: well stimulation and injection increase.

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.