Carbonate rocks are complex in their structures and pore geometries and often exhibit a challenge in their classification and behavior. Many rock properties remain unexplained and uncertain because of improper characterization and lack of data QC. The main objective of this paper is to study flow behavior of relative permeability with different rock types in complex carbonate reservoirs.
Representative core samples were selected from two major hydrocarbon reservoirs in Abu Dhabi. Rock types were identified based on textural facies, PoroPerm characteristics and capillary pressure. Porosity ranged from 15% to 25%, while permeability varied from 1 mD to 50 mD. Primary drainage and imbibition water-oil relative permeability (Kr) curves were measured by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. High-rate bump floods were designed at the end of the flooding cycles to counter capillary end effects. Aging period of 4 weeks was incorporated at the end of the drainage cycle. Robust data QC was performed on the samples, and final validation of the relative permeability was conducted by numerical simulation of the raw data and measured capillary pressure.
The followed QC procedure was crucial to eliminate artefact in the relative permeability curves for proper data evaluation. The different rock types showed consistent variations in the relative permeability hysteresis and end points. Imbibition relative permeability curves showed large variations within the different rock types, where Corey exponent to oil ‘no’ increased with permeability from 3 to 5, whereas the Corey exponent to water ‘nw’ decreased with permeability and ranged from 3 to 1.5. The variations in the relative permeability curves are argued to be the result of different rock structures and pore geometries. Variations were also seen in the end-point data and showed consistent behavior with the rock types.
The different carbonate rock types were identified based on geological and petrophysical properties. Higher permeability samples were grain-dominated and more heterogeneous in comparison to the lower permeability samples, which were mud-dominated rock types. Imbibition Kr curves showed larger variations than the primary drainage data, which cannot be interpreted based on wettability considerations only. The relative permeability curves have been thoroughly evaluated and QC'd based on raw data of pressure and saturation by use of numerical simulation. Such RRT-based Kr data are not abundant in the literature, and hence should serve as an important piece of information in mixed-wet carbonate reservoirs.
Relative-permeabilities are a first-order parameter to consider when describing multiphase-flows in porous media. Among many other parameters, the core wettability controls the fluids repartition in the porous media at pore-scale, strongly affecting how the fluids can be displaced (i.e. their relative-permeabilities). As the initial core wettability of reservoir sampled cores is rarely preserved, classical SCAL measurements (such as relative permeabilities) may not reflect the rock properties at reservoir conditions. This originate core wettability may be restored in a process referred as ‘core aging’. It is generally done by injecting the reservoir fluids (brine and crude-oil) in the core to equilibrate the rock surface with respect to the oil and brine components. Here, we investigated the effect of two aging protocols (static and dynamic) on wettability restoration, and characterize the aging using oil/water relative permeabilities measured on the core after aging. The two aging protocols were applied on a set of initially strongly water-wet outcrop sandstone samples (Bentheimer). The relative permeabilities were measured using the steady-state method and a state of the art experimental setup (CAL-X) based on X-ray radiographies. The setup is equipped with an X-Ray radiography facility, enabling monitoring of 2D local saturations in real-time and thus giving access to fluid flow paths during the flooding. Aged samples relative permeability curves show clear differences when compared to water-wet relative permeabilities, hence suggesting that the wettability has been effectively altered. However, the two aging protocols were unable to produce the same results. The dynamic aging has led to an inversion of the original relative permeability curves asymmetry, suggesting a strongly oil-wet system, whereas the static aging protocol has altered the wettability to a lesser extent. The differences can be explained by analyzing a 2D saturation maps. In the case of dynamic aging we observed a homogeneous distribution of fluid saturation during fractional flow. On the opposite, the static protocol results in heterogeneous flow paths, confirming that this protocol did not alter uniformly the wettability of the sample and generates a patchier mixed-wettability system.
Tahir, Sofiane (ADNOC) | Al Kindi, Salem (ADNOC) | Ghorayeb, Kassem (American University of Beirut) | Haryanto, Elin (Schlumberger) | Shah, Abdur Rahman (Schlumberger) | Yersaiyn, Saltanat (Schlumberger) | Su, Shi (Schlumberger) | Ali, Samad (Schlumberger)
Maturing giant and super giant fields have, typically, an extensive data set ranging from seismic data to time lapse surveillance data. The data set, associated studies and models together with driving values defined by ADNOC form the foundations of long-term plans, field development plans, business plans, reservoir management plans and production optimization plans. Ensuring the adequacy and optimality of the plans and their capability to meet their prescribed objectives is a very challenging task that requires unique assessment workflows. ADNOC is undertaking multiple fast-tracked Integrated Reservoir Performance and Production Sustainability Assurance (IPR) projects with the above objectives in mind. In this paper we will share the experience gained through the execution of such projects and the way this experience helped refining the workflows and the associated value.
We designed and applied unique workflows that combine "Bottom up" approaches by technical discipline with the "Top down" focusing on those factors that have the largest impact on the scope of the plans and the ability to deliver the expected outcomes. The identified issues and opportunities are presented in terms of their impact on volumes in place, reserves, facility, drilling plans, surveillance plans, modeling, etc. and are associated urgency indicators to help prioritizing actions.
The adopted integrated methodology and workflows helped in identifying and ranking various issues related to the reservoir models (static and dynamic) and many recommendations on how to tackle these issues in the new generation models were provided. Advanced reservoir management workflows were generated towards optimal production and injection balancing as well as to better manage the water flood and identify the most offending injectors. Many scenarios were explored to check the different elements of the full field development plan and ongoing projects, considering all the identified uncertainties. Many recommendations were provided, accordingly, concerning infill drilling and future gas lift program. Specific workflows were generated to optimize the performance of the existing gas lift wells and to identify and rank the future wells that will need gas lift according to their urgency, hence confirm the gas lift compression capacity that was subject of an ongoing project.
Key enabler to complete the project in the planed time frame was the use of cutting-edge modeling technology which has a drastic impact on the project and the team's capability to explore a comprehensive set of scenarios with associated sensitivities and uncertainty analysis providing unique insights towards more optimal decisions and clearer way forward.
Meziani, Said (ADNOC) | Ghorayeb, Kassem (American University of Beirut) | Al Zaabi, Najla (ADNOC) | Hafez, Hafez (ADNOC) | Al Katheeri, Abdulla (ADNOC) | Maldonado, Jorge (Schlumberger) | Khattak, Iftikhar (Schlumberger) | Haryanto, Elin (Schlumberger) | Chabernaud, Thierry (Schlumberger) | Yersaiyn, Saltanat (Schlumberger) | Kumar, Sayani (Schlumberger) | Shahid, Shawwal (Schlumberger) | Agam, Abdelrahman (Schlumberger) | Shah, Abdur Rahman (Schlumberger) | Chakraborty, Subrata (Schlumberger)
This paper describes a pragmatic approach for reviving a highly depleted major Oil Rim Reservoir after more than 30 years of massive gas cap exploitation. The main objective is to assess options and identify the optimal plan to re-develop the Oil Rim while honoring and not jeopardizing the gas and condensate production of the network and the existing facility constraints.
An integrated workflow was designed and implemented to understand the reservoir geology, field production history and to address requirements of both oil rim and gas cap developments. Analysis started by a dynamic synthesis to track oil/water contact (OWC) and gas/oil contact evolution with time using available surveillance data: MDT pressure gradient analysis with petrophysical evaluation (RST & OH logs).
A study consisting of a comprehensive review and update of the static and dynamic models was carried out to ensure the model adequacy for robust re-development planning. The dynamic model quality was assessed by comparing dynamic model results with surveillance data especially with regard to predicting the contacts movements and pressure variation vs. time in the different regions of the Oil Rim.
Production forecasting and optimal re-development plan identification followed a systematic approach aiming at assessing the incremental impact on oil recovery through the utilization of artificial lifting, different types of wells and completion as well as a variety of water injection scenarios. Sensitivity analysis included horizontal well lengths, well density, well placement, water injection and production capacity as well as economic constraints.
Oil production from this low-pressure oil rim reservoir has been a challenge due to the spread oil resources and complicated production mechanisms. The movement of OWC and GOC has been very sensitive and caused unfavorable early water/gas breakthrough. Despite the low recovery factor, some attempts to revive dead oil wells through artificial lift means (ESP, booster pumps) were made and considered as an initial step to reactivate the inactive wells.
The low oil production volume and hence low recovery makes the oil rim re-development economically less attractive. However, integration of state-of-the-art engineering approaches, proposed innovative technical initiatives and new technologies create an opportunity for significantly more economically attractive re-development.
The workflows used and discussed in this paper were tested for four other oil rim reservoirs and can be implemented in similar challenging oil rim development projects.
A giant oil field consisting of carbonate reservoirs in onshore Abu Dhabi has been provided with long term Field Development Plan, including several Dual Oil Producer (DOP) completions in formations Shuaiba and Kharaib, more specifically in zones A & B to maximize oil recovery. Upper Zone and Lower Zone B have been producing on natural flow using dual completions. This has been possible due to high reservoir pressures available since the beginning of the production.
Conditions have changed, especially for the Lower Zone B, and reservoir pressure has been declining for the past years. As a result, several wells ceased to flow mainly due to lower pressure and/or higher water cut conditions. Therefore, Gas Lift has been selected as the preferred artificial lift method in lower zone B.
The problem has been identified in current dual wells where Upper Zone is still producing but changing dual into Gas Lift single oil producer in lower zone B will translate into halt in oil production in upper zone, therefore reducing the oil recovery for Upper Zone. This is a consequence of the current practice of plugging and abandoning the Upper Zone.
An innovative application for dual oil producer completion with Gas Lift mandrels in long string has been evaluated to keep both zones producing and extend the ultimate oil recovery of the current wells. Candidate selection, including analysis and workflow, will be presented in detail. Moreover, the design process, well modelling and installation will be addressed further in this paper.
Chakib, Ouali (IFP Energies nouvelles, 1 et 4 avenue de Bois Préau, 92852 Rueil-Malmaison, France) | Elisabeth, Rosenberg (IFP Energies nouvelles, 1 et 4 avenue de Bois Préau, 92852 Rueil-Malmaison, France) | Loic, Barre (IFP Energies nouvelles, 1 et 4 avenue de Bois Préau, 92852 Rueil-Malmaison, France) | Jean François, Argillier (IFP Energies nouvelles, 1 et 4 avenue de Bois Préau, 92852 Rueil-Malmaison, France)
Two innovative characterization techniques, Small Angle Neutron Scattering (SANS) and High Resolution Fast X-ray Micro-tomography on a Synchrotron, have been combined to usual coreflood environments and X-Ray CT Scanner measurements in order to describe the texture of a foam flowing in an opaque 3D porous medium. SANS measurements give access simultaneously to the gas saturation and to the amount of gasliquid interfaces developed per unit volume and therefore to the in situ specific surface area of the foam denoted S/V. In situ texture of the foam flowing in real 3D porous media is therefore measurable. Fast X-Ray micro-tomography 3D images of foam flowing in a porous medium give visual evidence of the presence of gas bubbles in areas where the flow rate is naturally slowed by the trapping phenomena and enable to describe and follow the phenomena of intermittent trapping at the pore scale.
A key management guideline for water-driven, naturally fractured reservoirs (NFR) is to minimize water production. Water breakthrough is undesirable as it reduces oil production rate and lowers oil recovery. Managing these reservoirs involves delaying water breakthrough and mitigating its effects. This paper describes a cross-disciplinary workflow, which serves such purposes by making use of downhole pressure gauges (DHG) pressure data-based well models along with a dynamically validated fracture model.
The data-based well model is developed from our DHG pressure-production database. It has been field tested for forecasting water breakthrough, predicting water level in wells and planning for counteractive actions. The data-based well model is combined with a detailed fracture model whose elements were derived from the systemic integration of fracture types, genetic context and interaction with the carbonate host rock during diagenesis. The resulting workflow enables the well and reservoir management team (WRM) to put the well back in production after water-breakthrough in a way that maximizes oil re-saturation from tributary fractures into the main conductive features connected to the wellbore.
A field case illustrating the application of this workflow is discussed. The outcome of the application of this workflow is compared with the performance of other wells in which water breakthrough was dealt with by merely reducing their liquid rates till water cut became manageable. A complete set of relevant measured data, including downhole pressure gauge and a post breakthrough production logging tool (PLT), is discussed in the paper. Well performance puts in evidence that the workflow discussed in this paper allows for higher oil production rates and significantly lower water production rates following water breakthrough compared against more traditional approaches for handling wells after water breakthrough.
The workflow was developed through frequent iterations between near-wellbore flow performance data-based modeling and multi-scale fracture characterization, aimed to address the impact of the main conductive features and tributary fractures on well productivity. It is of interest to anyone involved in managing NFR, especially those engaged in preserving the sustainability of the oil potential of the well (both duration and rate).
A significant number of Kharaib horizontal and deviated producers drilled over the last decade have suffered from casing leaks, with many occurring in the first two years of production due to the exposure to highly corrosive water from the overlying giant water-bearing formation known as Shuaiba formation, resulting in production losses and water dumping from Shuaiba formation into the Kharaib reservoir through these damaged wellbores. This paper investigates the impact of Shuaiba dump flooding on the Kharaib reservoir’s performance, the integrated reservoir management study that was conducted and the implementation of the study’s findings to achieve the best results.
Severe casing leaks are the main production problems facing the Kharaib reservoir. A few repairs were attempted initially, however, high costs and failure rates led to a decision to cement squeeze all remaining casing leak wells, recomplete them in shallower reservoirs, and drill new replacement wells. All new Kharaib wells were designed with an extra casing to protect against the Shuaiba reservoir’s corrosive water. Although there are no longer any casing leak wells in Kharaib, their impact remains. The pre-casing leak production numbers and well counts are yet to be matched, and there is a large volume of hydrocarbons to be produced from the Kharaib reservoir. In addition, wells that are offset of old casing leak wells showed an increase in water cut, while the performance of new wells drilled down-structure of casing leak wells suffered from early water breakthrough. There is also strong evidence that the isolation in many casing leak wells, performed during the recompletion workovers, may be unsuccessful. All these factors indicate that dump flooding is likely ongoing in the Kharaib reservoir.
The consequences of dump flooding have not all been negative. An increase in average reservoir pressure and a strengthening of the reservoir’s weak water drive mechanism were observed. Currently, many wells have shown an increase in oil production, while other wells have shown steady oil production with a very gentle decline which is particularly reflected in wells located up-structure of the casing leaks. As a result of the study, many wells have been drilled in carefully selected locations in order to take advantage of the flooding, and the results of the study concluded a sustained production with a low water cut. Moving forward, there are further opportunities to increase the recovery factor by mitigating the unwanted effects of Shuaiba dump flooding and utilizing the phenomenon to its best potential.
Desai, Sameer Faisal (Kuwait Oil Company) | Al Jadi, Issa (Kuwait Oil Company) | Al-Ghanim, Wafaa (Kuwait Oil Company) | Franco, Francy Milena (Schlumberger) | Khor, Siew Hiang (Schlumberger) | Zhang, Qiong Michael (Schlumberger)
This paper discusses the development of a truly integrated asset model for the Greater Burgan oilfield in Kuwait linking multiple wells, pipelines networks, and process facilities for achieving integrated operational excellence in the South and East Kuwait asset of Kuwait Oil Company. A water handling facility model comprising of two effluent water disposal plants, a crude oil export pipeline network and a water injection network model are also incorporated into this integrated asset model. The main objective behind the development of this integrated asset model is to enable better asset management, faster and more precise decision making and enhancing the hydrocarbon flow path all the way from the reservoir till the export point.
The new integrated asset model was developed from a model centric approach involving construction and calibration of over 1500 well models. All wells were then linked to their network models comprising of pipelines totaling more than 10,000 km. The well and network models were integrated with the respective process facility models of the 14 gathering centers located in the field and finally tied to the crude export, water disposal and water injection systems. The results of the integrated wells to process facility models such as pressure gradient, temperature gradient and erosional velocity ratio gradient across the production network can be plotted or visualized on the Geographic Information System (GIS) map.
Integration of the vast number of wells and network models with the 14 crude processing facilities in a single IAM platform provides comprehensive understanding of flowing paths spread across the giant Burgan field and proves its utility as an effective flow assurance tool. The IAM platform also provides engineers and management an effective tool for analyzing well potential, identifying under-performing wells, spotting clusters of high water cut wells, singling out back pressure effected wells and locating system constraints. Thereby the proven IAM provides valuable information for effective production optimization and long-term surface facility development plans.
The IAM platform is designed for use by Reservoir, Production, and Process Engineers as well as Operations, Business Development, and Asset Management teams. Engineers can evaluate various scenarios to improve production and operation performance such as choke increase or decrease, re-routing wells between manifolds, adding new wells into the system, and decision on slots for connecting new wells to the plant headers. The IAM also enables asset teams to forecast injection rates, review the impact on the entire injection network in terms of pressure distribution, and conduct "what if" scenarios leading towards complete asset optimization.
Quantitative study of inter-well connectivity is significant for understanding which injector influence the producer, and making rational injection operations to improve water flooding efficiency. In this paper, a data driven method is presented to evaluate inter-well connectivity based on bottom-hole pressure of both injection wells and production wells.
In the development and production of fields, producers are always kept in constant production rate. Thus it is more appropriate to conduct inter-well connectivity analysis using bottom-hole pressure data rather than historical injection and production rates. However, the bottom-hole pressure data cannot directly obtained. The on-site monitored well head pressure and dynamic liquid level are first used to computation and obtain bottom-hole pressure for both injectors and producers. And then preprocessing the bottom-hole pressure using non-linear diffusion filters for capturing attenuation and time lag, and constituted the data set for machine learning. An artificial neural network (ANN) is then generated and trained to simulate connect relations between producers and its surrounding injectors. Genetic algorithm (GA) is also applied to optimize the time lag and hyper parameters of ANN, which helps to save time compared to subjective adjustments. In the last, sensitivity analysis is conducted on the well-trained ANN to quantify connectivity between injectors and producers, and detecting the connect status.
The proposed methodologies were first applied to two synthetic case, and then to real field case. The results were shown to be capable of capturing connection relations between injectors and producers, and highly consistent with known geological features, analyze results and tracer test of reservoir engineers. It indicates that the presented methods can be used to understand the flow direction of injected water, and guide to optimize water injection operation.