A fully compositional Integrated Asset Model (IAM) has been built for a giant gas-condensate field. The field is a complex retrograde gas-condensate reservoir with a hydrocarbon column up to 1750m in height. The fluid composition varies significantly with depth, ranging from a gas condensate to under-saturated oil. Production is centred on three processing facilities which are variously constrained by gas processing, gas compression & oil stabilisation capacities and overall export levels. There are some 100 producers and 15 gas injectors presently active in the field, with new wells and facilities planned as part of future development. IAM's for the total production system have been gaining in popularity for applications such as FEED studies, field development planning and optimisation. Their complexity has grown with the need to have fully compositional models, which are particularly important for gas condensate fields, where accurate fluid description is required for predicting condensate recovery and injection gas composition. Development of this IAM has required close cooperation between reservoir, production and process engineers since each of the component models - a 3D reservoir simulation model, production & injection surface network models and a process model for the three production units – are complex in their own right. The IAM model honours the well, network, and facilities constraints, taking into account interdependence between the different elements of the system. The IAM provides the capability to manage scheduled field events (well re-routing, plant maintenance, field uptime, etc) and optimizing field liquid production. This work offers valuable insights for more accurate assessments while evaluating different field exploitation strategies.

Downhole Natural Gas Separation Efficiency (NGSE) is flow regime dependent, and current analytical models in certain conditions lack accuracy. Downhole NGSE was investigated through 3D Computational Fluid Dynamics (CFD) transient simulations for pumping wells in the Churn flow regime. The Volume of Fluid (VOF) multiphase model was considered along with the k – ε turbulence model for most simulations. A mesh independence study was performed, and the final model results validated against experimental data, showing an average error of less than 6 %. Numerical simulation results showed that the steady state assumption used by current mathematical models for churn flow can be inaccurate. Several key parameters affecting the NGSE were identified, and suggestions for key improvements to the widely used mathematical formulations for viscous flow provided. Sensitivity studies were conducted on fluid/geometric parameters and operating conditions, to gain a better understanding of the influence of each parameter on NGSE. These are important results as they equip the ESP engineer with additional knowledge to maximise the NGSE from design stage to pumping operations.

It’s no common news were pipelines/facility may be oversized or undersized, due to some certain traditional norms or nominal constraints imposed. When considered with the harsh subsea environments and long tie backs which the industry experiences these days, then it is highly important that the design of the production surface network is optimized efficiently. It could save remarkably millions of dollars. All thanks to advanced modelling approaches, where the concept of integrated modelling has shone brightly. The traditional methods practiced by the flow assurance engineer involves obtaining reservoir simulation production profiles either uncertainty profiles (P10, P50 & P90) to early, mid and late field life for engineering design/debottlenecking of surface networks. These methods rely heavily on the assumption that those profiles which form the basis of design are healthy for providing boundary conditions for the surface network. In most cases the engineer does not contest/ understand how these profiles were obtained from reservoir simulation and what controls the wells were subjected to. As an example, a natural well could have been subjected to a nominal well tubing head pressure control (staying constant) for about three quarter of its life. This is a major limitation or "gap" in the traditional approach; it could lead to wrong design and estimations of the thermo-hydraulic responses. In this paper we introduce the concept of integrated modelling for the flow assurance engineer and compare it to the traditional approach. We show three case studies. The first shows a real case where the IAM corrected a design for a North Sea gas condensate field saving millions of dollars. The second shows how IAM aids an engineer in sizing a line with known indicators such as (mean slug length, Erosion velocity) and the third uses the integrated model to identify wax, asphaltenes and corrosion possible areas.

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Berkine basin is one of the main oil producers in Algeria. The upper, middle, and lower TAG-I are the target oil-bearing sands. In this basin, the ROD field is under pressure maintained mainly through water injection together with, to a lesser extent, gas injectors. The southern part of the field, "ROD Tail" has four water injectors targeting the middle TAG-I. In recent evaluation conducted through pressure measurement and an interference test, reservoir pressure was found to have declined by 35 bar within 2 years. This has prompted questions about reservoir management, mainly about the effectiveness of injector well capacity in maintaining reservoir pressure. Extensive data were gathered through well intervention; cleanout, perforation, and a caliper log. Many failed acid jobs were also noted in the history of these wells. An engineered high-pressure jetting operation via coiled tubing was executed, but injectivity could not be restored. A methodology and workflow were adopted to identify the source of formation damage and scale deposition in the near-well area and around perforations. Solid samples were collected from the well and sent to laboratory to characterize formation damage type. The injection water was also analyzed by performing a standard 12-ion concentration analysis. An aqueous model simulator was used to confirm that the water was supersaturated with CaSO4 and CaSO4.2H2O. Finally, clay acid treatment was found to be effective. The treatment fluid was designed to prevent proppant dissolution and to clean fracture matrix interface. This was the first time this type of operation was executed after many unsuccessful conventional acidizing operations. Excellent results were obtained after the acid stimulation treatment. The injection rate was found to increase significantly from 120 m3/d to 360 m3/d. Water injection pressure was also found to decrease from 243 bar to 220 bar, and the injectivity index increased by three times. Near-wellbore formation damage was removed, and formation permeability recovered. The clay acid treatment was applied to other wells in the field and similar results were obtained.