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 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 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 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.

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.

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.

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).