Hydrodynamic Optimisation and Production Enhancement (H.O.P.E.)

Reservoir management is a complex process with
constant uncertainties in reservoir performance
due to the inability to fully characterise reservoirs
and flows.

TGT has designed a new technique called Hydrodynamic Optimisation & Production Enhancement (H.O.P.E.), which measures effective injected or produced fluid flow, locates flow fronts and determines inter-well reservoir properties in order to minimise uncertainties and have realistic parameters to put into a model, calibrate it and assess and improve the field development plan.





The first stage is data gathering and job design. Well and reservoir data are collected, working cells are defined, and data acquisition needs are addressed.


The second stage is data acquisition. In this stage, X-Well Tomography is conducted to determine reservoir heterogeneity, continuity, fluid font displacement and other properties, such as dynamic permeability, formation compressibility, diffusivity and transmissibility.


The third stage is data analysis and interpretation. The outcome of this stage is to be integrated into the reservoir model. (Production reallocation and/or injection distribution, inter-well reservoir properties, sweep and displacement efficiency, etc.)


The fourth stage is data integration. TGT works closely with the Customer on a consultancy basis to put new data into the model, performing 3D model calibration and history matching. On the same basis, TGT offers a series of sensitivity analyses for production enhancement and optimisation opportunities based on the study.

Watch Video

3D Model
Calibration (3D-MC*)



Image 1

Reservoir models built on the assumption that permeability always controls flow, sweep and recovery can be misleading. Heterogeneity can prevail across the field, discontinuity could be more severe than shown by seismic, or the zone itself can be damaged, leading, for example, to serious errors in history matching and subsequent forecasts.

The 3D Model Calibration (3D-MC*) is a fine-grid reservoir flow simulation technique that uses actual fluid flow and saturation profiles from TGT's Platforms to calibrate reservoir performance along the well trajectory. The key feature of the TGT’s 3D MC is a calibration procedure for all wells in a sector, where flow/saturation data have been acquired along the wellbore. The 3D-MC* will in this case maximise the value of the data that are already in hand.

Hardware & software tools


Indigo PL Suite Indigo PNN


  • Calibrate fine-grid dynamic model to the flux
  • Match the model to history data and build flow scenario

Criteria for Candidates Selection

  • Poor match between dynamic model and production performance

Inputs for Candidates Selection

  • Production History vs Forecasts for all offset wells
  • Formation tops and perforations for all offset wells

Inputs for Job Proposal

  • Maps with well locations, formation tops and GOC/OWC contacts
  • Production History and latest tests for selected wells
  • Well sketch for selected wells
  • Formation tops for selected wells

Inputs for Interpretation and Analysis

  • Flux profiles from reservoir flow logs (QZI)
  • Water/gas breakthrough zones from saturation logs (Sweep)
  • OH logs in LAS (lithology, porosity, saturation, permeability) for selected wells
  • Geological fine-grid sector/field model in Petrel or rescue format
  • Dynamic sector/field model in Eclipse format

Why fine-grid flow simulations?

The modern geological models are normally built in fine-grid (20 m – 50 m grid size or less). Conventional full-field flow simulations are usually performed over an upscaled grid (100 m – 300 m) in order to save on computation time and average the calculated pressure/saturation to tame the uncertainties in well-by-well data. Upscaling is a reasonable procedure in single-layer homogeneous reservoirs. But if the reservoir has an uneven permeability profile or made up of multiple formation units the upscale procedure can seriously damage the actual picture of fluid propagation, often leading to confusion.

The picture below shows that an upscaled water propagation scenario can miss the moment when water is actually reaching the producer. It happens when the upscaled model blurs permeability profile and simulated flow extends to the layers which in reality do not flow.

Fine-grid simulations

Obviously, fine-grid flow simulations have no practical value until the flow scenario is calibrated to the downhole measurements of the actual reservoir flux profile.

Why matching the flux?

Reason #1 – Complicated reservoir flow profile

The actual reservoir flow rate is a function of formation permeability, formation pressure and wellbore skin-factor, and all the above may vary across the production/injection zone. Unlike permeability and pressure, there is no reliably measured data on skin variation along hole. Without flux calibration the simulation software will be moving fluid through all formation units following the permeability and pressure profile. In reality, not all formation units are taking water or producing fluid as scheduled by the permeability model.

The picture below shows a case when non-calibrated model (left) does not see the water coming through the lower part of formation (right) and will be struggling to explain the early water breakthrough in offset producer.

Matching the flux Reason 1

There are several reasons why water goes to the lower permeability formations. But as soon as the actual reservoir flow profile is measured through with downhole tools these data should be used to calibrate the 3D model, which will obviously lead to more reliable production forecasts.

Reason #2 – Behind-casing communication

In many practical cases the actual injection water channels above or/and below perforations making reservoir flux profile very different from the one specified in the input schedule of 3D model.

The picture below shows that most of injection water channels up behind casing to the lower permeability reservoir. The further study revealed this was caused by intense depletion of the upper reservoir in this area.

Matching the flux Reason 2_1

Very similar complicacies arise in producers: fluid (oil/gas/water) often propagates through non-perforated formation unit and once approaching borehole it channels up/down towards the perforations. The picture below shows a thief water production from a lower formation.

Matching the flux Reason 2_2

The above cases create a lot of problems in history matching and provoke simulation engineers to overplay with “localized” permeability and “non-neighbour connections” thus taking dynamic model even further away from reality.

How to measure the flux?

The actual reservoir flux profile can be assessed through the spectral noise log and wellbore temperature modelling of “flowing against shut-in” response.

Spectral Noise logging technique localizes the flow units behind the casing (even if tool is conveyed through the tubing). But it needs temperature modelling to evaluate the flow rate in each unit as noise amplitude is not always a fair measure of flow rate. The flow rate evaluation technique is based on numerical simulation of borehole temperature profile under stabilized flowing conditions (several hours or more) and stabilized shut-in conditions (usually 4-5 days).

The picture below shows that injection temperature is not clearly responsive to location of behind-casing injection streaks and shut-in temperature is smeared across perforations due to developed heat transfer and it needs a spectral noise log to see the actual location of flow units.
Anyway, the noise-temperature combination shows that injection is equally shared between two narrow formation streaks (rightmost panel).

Measuring flux

The combination of these measurements makes up an essential part of MGFM.

Why PLT is not enough?

Conventional spinner-based PLT survey measures production/injection profile inside borehole and cannot account for redistribution of the flow behind the casing and can’t be used in 3D calibration procedure.

Case #1 – Behind-casing redistribution

The picture below shows that only one formation unit is actually dispatching the flow through all perforations:

Combining with PLT Case1

Even if injection/production stays within the perforated interval, in many practical cases PLT is the source of confusion and misunderstanding of reservoir behaviour

Cement fracturing and wash-outs create a buffer zone where flow from the bottom formation A4 dispatches fluid across all perforations producing an illusion that all formations A2, A3 and A4 are contributing to production.

Case #2 – Channelling

The picture below shows a thief water production from a lower formation.

Combining with PLT Case2

PLT profile shows oil-water production from perforations and does not realise that reservoir across perforation produces oil only and all water is channelling from the lower formation.

Saturation calibration

Residual saturation is a function of flux and relative permeability of rocks.
Once the flux is matched one can adjust relative permeability to match the saturation logs.

The picture below shows that injection water is halfway towards producer while saturation log shows an early water breakthrough in lower formation.

Saturation calibration1

The flux measurements and calibrations confirm that inejction water is equally shared between two formation units. This leads to the stage when adjustment to relative permeabilities is required.

The picture below shows that relative water permeability has been modified and resulted in good match with saturation measurements.

Saturation calibration2

It is important to note that MGFM uses saturation logs only to check for formation layers which are invaded by water and discards the actual value of saturation because the latter is often inaccurate.