This paper summarizes the integrated technical learnings from the successful application of a an Autonomous Inflow Control Device (AICD) in new long horizontal wells producing heavy oil in multiple fields and show the result of extending this technology to the old producers in the field. It details the facts and observations that multidisciplinary authors have captured. The AICD was completed in more than 40 new oil wells in multiple fields. It comprises of mechanical devices installed with the sand face completion, which react in real time to the properties of the flowing fluids, decreasing/delaying the water influx from high productivity zones, promoting increased oil production from other compartments of the formation, therefore, equalizing the drawdown along the horizontal section of the well and performing a dynamic water shut-off operation. The great successful result from new oil wells with this technology AICD opened the door to do few trials in existing producers. The AICD-completed wells showed initial water cut in the range 1% to 2%. Which had reduced significantly in comparison to nearby analogues. The initial net oil rate resulted to be more than 2 times of the expected one, with an acceleration of ~10,000 bbls of net oil during the first month. After the initial production period, the technology is still delaying the aggressive water cut development usually observed in these fields, having provided 2 times the expected net oil rate during the first 3 months, with an acceleration of approximately 20,000 bbls of net oil over this period. It has been concluded that the application of the technology is successful and already deployed as a baseline in all future horizontal wells drilled. Also this technology was tried in old producer wells and already 15 wells completed with AICD completion which shows good reduction in gross/water and increase in oil production in some of the wells by more than 30%. With these successful results, 35 wells from existing producers were planned to be completed by AICD in 2020 from multiple fields. The authors have summarized the results from the AICD deployment and presented it as a practice worth replication in a similar heavy oil environment, due its many benefits in optimizing field development. AICD in new and old wells will be a game changer in all filed to reduce the water and increase the oil.

This investigation was made to clarify the type of reservoir fluids in an Iraqi field reservoirregarding the controversy about its type. It was known for many years as a condensate field, butin this study a different theory was investigated and proved using Winprop of CMG® software.Two equations of state (EOS) were tested and the one with minimum error percentage was used.Also, three correlations were tested to calculate the original C6+ properties, which are: Lee-Kesler , Twu and Riazi . Twu`s correlation prevailed because the results of this correlation werethe nearest to the original data, and it permits using a wide range of pressures (from zero toinfinite pressure values), which minimizes the discrepancies between the results of any equationof state, which was investigated.After achieving the closest possible match of all available properties, the envelopes wereconstructed. Winprop of CMG needs a full set of oil and gas properties from a single sample.Therefore, a recombination for the available gas and oil samples were made to construct thephase envelopes for the field system in addition to individual gas and oil phase envelopesThe result of this investigation and analysis is that the reservoir is actually a black oil field with agas cap, despite what was believed earlier as being a condensate field.

One of the principle inputs to project economics and all business decisions is a realistic production forecast and a practical and achievable development plan (i.e. waterflood). Particularly this becomes challenging in supergiant oil fields with medium to low lateral connectivity. The main objectives of the Production Forecast and feasibility study for water injection are: 1- Provide an overview of the total expected production profile, expected wells potential/spare capacity, water breakthrough timing and water cut development over time 2- Highlight the requirements to maintain performance, suggest the optimum development pattern 3- Increasing confidence in business decisions to develop the reservoir in question The main tool used for these purposes is a sophisticated reservoir simulation software, namely CMG©, since it can predict reservoir behavior, honor physical constraints and capture the heterogeneity within the reservoir to accurately predict performance. However, the starting point for this kind of complicated studies needs to start from the basics, in order to understand the big picture and be able to plan properly for the scope to be delivered, hence, utilizing analytical tools like MBAL becomes quite necessary, if not crucial, to the success of full field modelling and choosing an optimum water flood pattern and design. This paper covers the methodology for building the reservoir component utilizing a Material Balance model, of which the results will be used as an input to reservoir simulation to evaluate and accurately predict reservoir performance, which directly feeds into planning for water flooding projects and selection of an optimum flood pattern. A Tank model was built at first to assess and understand the driving forces (energies) of the reservoir in question, utilizing pressure and production data from legacy wells, the prepared model is also supported by geological and petro physical studies to give representative results. Acquired Static Bottom Hole Pressures (SBHPs) in wells were used as anchor points for the tank pressure and to test the validity of the history match. Multiple analytical methods to QC the results and STOIIP volume were conducted, e.g. the Havlena-Odeh method. This methodology has been tested successfully in the stated super giant oil field, in which the reservoir in question is a carbonate rock formation. An example of this is covered in the paper. It was concluded that utilizing a history matched and coherent MBAL model before conducting a detailed reservoir simulation study can save a lot of time and effort by providing guidance to the path which needs to be followed, and sheds light on the critical elements to be looked after. This has also helped to uncover the driving mechanisms and energies in the reservoir, hence allowing the engineer to plan for the necessary voidage replacement and water injection rates to sustain the reservoir pressure and pattern development. Another technical advantage of the described method is the higher sustainability of the model. The suggested method, in combination with geological and petro physical information available, can be applied to majority of the reservoirs. This combination is paramount to ensure optimum time and planning that is followed for each reservoir development study that involves water flooding.

One of the principle concepts for understanding the hydrocarbon field is the heterogeneity scale; this becomes particularly challenging in supergiant oil fields with medium to low lateral connectivity in carbonate reservoir rocks. The main objective of this study is to quantify the value of the heterogeneity for any well, and propagate it to the full reservoir. This is quite useful specifically prior conducting detailed water flooding or full field development studies and work, in order to be prepared for a proper design and exploitation requirements, which fits with the level of heterogeneity of this formation. The main tool used for these purposes is the application of the famous Lorenz coefficient method, in conjunction with the Dykstra Parsons technique for calculating the degree of heterogeneity for any well.  The starting point for this kind of complicated studies needs to start from the basics. In order to understand the big picture and be able to plan properly for the scope to be delivered. Utilizing analytical tools like the ones mentioned above becomes quite necessary, if not crucial, to the success of full field modelling and choosing an optimum water flood pattern and design. This work covers the methodology for quantifying and calculating the level of heterogeneity in a given reservoir. The Dykstra-Parsons Coefficient or the variation of Dykstra Parsons (VDP) is commonly used in calculating permeability variation. The method of calculating begins by sorting the property of interest and make the other property fixed value (to calculate permeability you have to make porosity a fixed value for all calculations) and make permeability in order of decreasing magnitude. For each of the values calculate the percentage of values greater or the ‘cumulative probability’, so that the probability of X is P(x≤X). Then plot the original permeability values on a log probability graph with the cumulative probability values. The slope value and the intercept of the line of the best fit, for all data are used to calculate the 50th and 84th probability values or by variation layering system to calculate the variation of P10, P50 and P90, which are used to find VDP. This methodology has been tested successfully in the stated super giant oil field, in which the reservoir is a carbonate rock formation. The reservoir is areally extensive reservoir and not of a great thickness. The importance of this step is to conclude a utilizing heterogeneity calculation method before conducting any detailed reservoir simulation study. It can save a lot of time and effort by providing guidance to the path, which needs to be followed, and sheds light on the critical elements to be looked after. This also can help to uncover many insights on the reservoir itself, hence allowing the engineer to plan for the necessary voidage replacement and water injection rates to sustain the reservoir pressure and pattern development based on the magnitude of heterogeneity those results from this procedure. The suggested method, in combination with geological and petrophysical information available, can be applied to majority of the reservoirs. This combination is paramount to ensure optimum time and planning is followed for each reservoir development study that involves for example water flooding

The South Oman clusters A and B have reclassified their Deep-Water Disposal wells (DWD) into water injection (WI) wells. This is a novel concept where the excess treated water will be used in the plantation of additional reed beds (Cluster A) and the farming of palm trees (Cluster B), as well as act as pressure support for nearby fields. This will help solve multiple issues at different levels namely helping the business achieve its objective of sustained oil production, helping local communities with employment and helping the organization care for the environment by reducing carbon footprints. This reclassification covers a huge water volume in Field-A and Field-B where 60,000 m3/day and 40,000 m3/day will be injected respectively in the aquifer. The remaining total excess volume of approx. 200,000m3/d will be used for reed beds and Million Date Palm trees Project. The approach followed for the reclassification and routing of water will: Safeguard the field value (oil reserves) by optimum water injectionMaintain the cap-rock integrity by reduced water injection into the aquifer.Reduce GHG intensity by ±50% as a result of (i) reduced power consumption to run the DWD pumps and (ii) the plantation of trees (reed beds and palm trees).Generate ICV (in-country value) opportunities in the area of operations for the local community to use the excess water at surface for various projects.Figure 1DWD Reclassification benefits Multiple teams (subsurface. Surface, operations), interfaces and systems have been associated to reflect the re-classification project. This was done through collaboration of different teams and sections (i.e. EC, EDM, SAP, Nibras, OFM, etc). Water injection targets and several KPIs have been incorporated in various dashboards for monitoring and compliance purposes. Figure 2Teams Integration and interfaces It offers not only a significant boost to the sustainability of the business, but also pursues PDO's Water Management Strategy to reduce Disposal to Zero by no later than the year 2030 This paper will discuss how the project was managed, explain the evaluation done to understand the extent of the pressure support in nearby fields from DWD and the required disposal rate to maintain the desired pressures. Hence, reclassifying that part of deep-water disposal volume to water injection (WI) which requires a totally different water flood management system to be built around it.