Data-Driven subsurface modeling technology has been proven, for the past few years, to yield technical and commercial success in several oil fields worldwide. A data-driven model is constructed for the first time for an oil field onshore Abu Dhabi, and used for evaluation of a reservoir with substantial reserves and comprehensive development plan; for the purpose of predicting production rates, dynamic reservoir pressure and water saturation, improving reservoir understanding, supporting field development optimization and identifying optimum infill well locations. The objective is to provide the asset with a decision-support tool to make better field development planning and management.
The subject reservoir is a low permeability carbonate reservoir and characterized by lateral and vertical variations in its reservoir rocks and fluid properties. More than 8 years of Phase-I development and production/injection data and extensive amount of well tests and log data (SCAL, PVT, MDT) from more than 37 wells were used to construct the Data Driven Model for this asset.
This new modeling technology, (TDM), integrates reservoir engineering analytical techniques with Artificial Intelligence, Machine Learning & Data Mining in order to formulate an empirical and spatiotemporally calibrated full field model. In this work, it is leveraged with other conventional reservoir modeling and management tools such as streamline modeling, isobaric maps and flooding conformance.
Several analyses were performed using the full field data-driven model; complementing the existing conventional numerical model. The accomplishments of the data-driven reservoir model for this project included, but not limited to, comprehensive history matching (including blind validation) and then forecast of Oil rate, GOR, WC, reservoir pressure and water saturation, injection optimization, and choke size optimization. The results generated by the data-driven model proved to be quite eye-opening for the asset management; as the model was able to identify potential areas of improving field efficiency and cost reduction.
When combined with numerical techniques, the calibrated data-driven model assist to obtain a reliable short term forecast in a shorter time and help make quick decisions on day-to-day operational optimization aspects. The use of facts (all field measurements) instead of human biases, pre-conceived notions, and gross approximations distinguishes data-driven modeling from other existing modeling technologies. Its innovative combination of Artificial Intelligence and Machine Learning (the technologies that are transforming all industries in the 21st century) with reservoir engineering, reservoir modeling and reservoir management clearly demonstrates the potentials that these pattern recognition technologies offer to the upstream oil and gas industry for its realistic digital transformation.
Gazar, Ashraf Lotfy El (Abu Dhabi Company for Onshore Petroleum Operations Ltd. ADCO) | Alklih, Mohamad Yousef (Abu Dhabi Company for Onshore Petroleum Operations Ltd. ADCO) | Al-Shabibi, Tariq Ali (Abu Dhabi Company for Onshore Petroleum Operations Ltd. ADCO) | Latief, Agus Izudin (Abu Dhabi Company for Onshore Petroleum Operations Ltd. ADCO) | Fauzi, Tengku Mohd (Abu Dhabi Company for Onshore Petroleum Operations Ltd. ADCO) | Syofyan, Syofvas (Abu Dhabi Company for Onshore Petroleum Operations Ltd. ADCO) | Hashimura, Tadashi (Abu Dhabi Company for Onshore Petroleum Operations Ltd. ADCO)
This work presents a case study of developing the transition zone for a giant oil reservoir with significant gas cap and water aquifer, in Abu Dhabi-UAE, addressing geological and dynamic aspects, field development approach and present status. The reservoir lies within a relatively low relief heterogeneous carbonate structural trap and characterized by lateral and vertical variations in reservoir rock and fluid properties. Given the relatively low permeability of the mentioned reservoir, the transition zone contains a significant STOIIP; which called for this challenging development.
A number of parameters were addressed and optimized as part of the transition zone development plan. The dynamic modeling suggests that a full field ultimate recovery of 70% can be achieved by developing the transition zone. However, considering the complexity of the reservoir, thickness of the transition zone and current market conditions, the field development would be economically viable for a period of 50 years under miscible hydrocarbon WAG, provided the most effective development strategy in terms of the definition of transition zone, optimization of the number, location, orientation and horizontal reach of the proposed wells. Various development strategies for the transition zone were investigated during the study considering all possible uncertainties and economic drivers, all of which are discussed in details in this paper.
12 years of early production scheme (EPS, 1993 to 2005) and 12 years of phase-I development helped better understand the reservoir and characterize the transition zone. Total of +150 wells penetrated the reservoir with good data gathering (ROS, Core, SCAL, PVT, MDTs…etc.). PVT studies indicate a wide range of compositional variation areal and vertical, which further complicates the development plan considering the surrounding sensitive environment.
The transition zone is defined by rock types and the corresponding critical saturation. The amount of recoverable oil in the transition zone is depending on the distribution of oil saturation as a function of depth and the relationship between initial and residual oil saturation in the transition zone.
The reservoir is under EOR (Miscible HC GI at crest and WAG at flank) since commissioning of phase-I in 2005 and tracers were injected in 2012; adding challenges to the history matching and tracking of the flood front. Given the limitation on surface handling capacity of the current facilities, the transition zone development called for well placement in the upper part of the transition zone using 6 months WAG cycles. The first well of the transition zone development has been drilled; which has positively validated the definition of the transition zone, built confidence on the subsurface modeling approach and commended the planning strategy.
Yegin, Cengiz (Incendium Technologies LLC) | Temizel, Cenk (Aera Energy) | Yegin, Yagmur (Texas A&M University) | Sari, Mufrettin Murat (Texas A&M University) | Jia, Bao (University of Kansas) | Alklih, Mohamad Yousef (ADCO)
Hydraulic fracturing is an important method to recover shale oil and gas that has drastically increased U.S. energy production in recent decades. Shales are low permeability formations where natural resources are trapped, and require a well-planned hydraulic fracturing process and a highly developed fracturing (fracking) fluid for efficient oil/gas recovery. In this study, a pH-responsive solution synthesized by supramolecular assembly of maleic acid and an amino-amide in an aqueous media is described as a potential fracking fluid owing to its mobility control, proppant carrying and settling capacities. Previous investigations on this solution system had shown its large potential to replace displacement fluids in EOR due to pH-tunable and reversible viscosity behavior.
The main working mechanism is that; the initial viscosity of injected solution is kept at moderate/high values to easily transport proppants and easily inject the fluid; and then decreased when the solution reaches a position near fissures for settling of proppants. It has been reported by rheology tests of the developed fracking fluid, which consists of the supramolecular solution and proppants (silica sand), viscosity can be changed about 1600 times from pH 3.8 to pH 8.3 in a reversible fashion at only 2 wt.% concentration. On the other hand, sedimentation studies indicated that the sedimentation speed of the silica proppants decreased around five orders of magnitude from pH 4 to pH 8, again in a reversible way. Furthermore, experimental studies revealed that the developed supramolecular solutions have both reversible pH-responsive properties, and tolerance against high salinities and elevated temperatures. Another outstanding property of these supramolecular solutions is their self-healing feature which enables them to disassemble and reassemble upon exposure to extreme shear stresses, while polymer viscosifying agents the fracking fluids degrade and break up under similar conditions.
The supramolecular assembly system discussed in this study has a promising potential to become next-generation fracking fluids with its outstanding properties including but not limited to pH-sensitivity, reversible viscosity, high proppant transfer capacity, tolerance to high temperatures and salinity, self-healing behavior, environmental friendliness and sustainability.
Kumar, Ravi (ADCO) | Al-Shabibi, Tariq Ali (ADCO) | El Gazar, Ashraf Lotfy (ADCO) | Alklih, Mohamad Yousef (ADCO) | Syofyan, Syofvas (ADCO) | Latief, Agus I. (ADCO) | Fauzi, Tengku Mohd (ADCO) | Trejo, Lenin Loredo (ADCO) | Khan, Muhammad (ADCO) | Al Kathiri, Taghreed H. (ADCO) | Al-Naqbi, Sheikha O. (ADCO)
The work discusses the unique challenge of developing deep and thin oil reservoirs spread across onshore and offshore area of Abu Dhabi. The field is being developed with a cluster development approach utilizing available Natural/artificial Islands in offshore areas. The reservoirs under considerations are thin heterogeneous carbonate reservoirs with moderate permeability (avg ~<10-15 mD) and containing volatile to critical oil.
The reservoirs were discovered quite early; limited data is gathered in old wells and have associated uncertainties. Some wells were deepened for sake of collecting additional data; very few completed lately under early production scheme (EPS) to evaluate the well potential, performance sustainability, reservoir drive etc. Their production behaviors also carry an overprint of reservoir diagenesis. The available data, their associated uncertainty and EPS performance are combined to build a holistic reservoir understanding and field development plan, under implementation with phased drilling. An early water-alternate-gas injection (WAG) is planned to support declining reservoir pressure in volatile oil reservoirs in absence of aquifer support.
These reservoirs comprise of thin parasequences (<10 ft) separated by dense intervals associated with stylolites; reservoir thickness falling below seismic separation limit. The structural setting is complex due to undulating anticlines and extensive faulting. Diagenesis has heavily influenced reservoir properties, making significant reservoir saturation profile variation both laterally and vertically. This has been confirmed with production performance of EPS wells, behaving differently due to their areal location. The current development plan considers producers with 4000’ horizontal lateral in high oil saturation along with multiple sub-zone coverage to achieve an effective depletion strategy. The limited data availability, structural uncertainty and reservoir heterogeneity in combination with limitation of cluster drilling rig capacity has made well placement a challenging task. Placement of horizontal laterals in good reservoir properties, away from gas cap or O/W transition zones is achieved by utilizing unified understanding of structure, carbonate lithology, diagenesic imprints, logs, analogue saturation-height function, openhole tests and production data. The learning from each new well is incorporated to optimize further development plan. The reservoir quality of completion interval is critical in terms of saturation considering water production, well lifting and long term sustainability. The learning from successful implementation of WAG in another reservoir of the field is incorporated.
Understanding from production behavior during EPS has provided a broad guideline for reservoir development; this paper discusses the challenges of implementation and their mitigation approach.
Scale-inhibitor-squeeze lifetime is measured by the duration for which the scale-inhibiting chemical is released at a concentration greater than the required minimum inhibitor concentration (MIC). Hence, enhancing scale-inhibitor adsorption and storage may proportionately enhance squeeze lifetime. With most oilfield squeeze scale inhibitors being aqueous-based, they are unlikely to be adsorbed on an oil-wet formation in optimal quantity. Investigations are made in this research on how to create the appropriate formation condition so that adsorption and lifespan of scale inhibitor in an oil-wet carbonate reservoir are enhanced, focusing on preflush design (formation-conditioning stage). Surfactants (of anionic and nonionic type), a cosurfactant, and alkali are deployed and results are evaluated through interfacial tension (IFT), phase-behavior analysis, coreflood studies, and inductively coupled plasma-mass spectroscopy (ICP-MS) analysis. Flow experiments are conducted in simulated reservoir condition by use of data and materials from a high-temperature and high-salinity carbonate reservoir. The results reveal that nonionic surfactant is most favorable in terms of scale-inhibitor-squeeze lifetime, which is enhanced by as much as 240% compared with conventional treatment. It is concluded that through correct preflush design and formation conditioning, scale-inhibitor-squeeze lifetime can be extended significantly.
Scale inhibitor (SI) squeeze treatment is an established practice in offshore fields to prevent inorganic scale deposition in the wellbore and near wellbore formation. Squeeze lifetime is measured by the duration for which the concentration of the chemical is released at a concentration above the required minimum inhibitor concentration (MIC). Hence, maximizing SI adsorption to the pore surfaces may proportionately enhance squeeze lifetime. However, most oil-field squeeze scale inhibitors being aqueous-based, it is unlikely to get optimum adsorption on an oil-wet formation due to unfavorable rock surface condition. This work is targeted towards optimum formation conditioning through an intelligently designed pre-flush treatment; so that the adsorption and lifetime of SI in an oil-wet carbonate reservoir are significantly improved.
Eco-friendly APG surfactants are evaluated with and without alkali and co-surfactants to design the pre-flush composition. A series of coreflood experiments are conducted in simulated reservoir conditions, using data and materials from a high temperature carbonate oil reservoir from the Middle-East. The results are evaluated in light of IFT and phase behavior and changes of rock wettability due to pre-flush treatment.
The results show that SI squeeze lifetime can be enhanced by as much as 240% when compared to conventional treatment and it has a direct correlation with wettability index and IFT. Anionic surfactant may look more attractive than nonionic surfactant due to favorable wettability alteration and highly reduced IFT, however they may not be the right choice for carbonate formation due to higher adsorption and competition with scale inhibitor molecules. Cost benefit analysis evince that introduction of the newly designed pre-flush treatment would results in improved economics through reduced treatment frequency, leading to minimized well intervention and consequent production loss.
Not enough attention is given on the design/optimization of pre-flush and conditioning of the formation to be used as adsorbent/storehouse of the inhibiting chemical in preferentially oil wet carbonate formations. The applicability of surfactant-alkaline has been long established as means of EOR mechanism but they are rarely investigated for near wellbore treatments to maximize chemical storage and placement; which is what this work has studied.
El Gazar, Ashraf (Abu Dhabi Company for Onshore Petroleum Operations Ltd.) | Bin Sumaidaa, Saleh A. (Abu Dhabi Company for Onshore Petroleum Operations Ltd.) | Alklih, Mohamad Yousef (Abu Dhabi Company for Onshore Petroleum Operations Ltd.) | Syofyan, Syofvas (Abu Dhabi Company for Onshore Petroleum Operations Ltd.) | Al Shabibi, Tariq Ali (Abu Dhabi Company for Onshore Petroleum Operations Ltd.)
This paper presents a case study of developing a significant volume of super K compartmentalized oil reservoir with a large gas cap and bottom water aquifer in Abu Dhabi-UAE. The reservoir is a low relief heterogeneous carbonate, located in a complex environment represented by natural and artificial islands in the surface, shallow and medium water marine areas with subsurface lateral, and vertical heterogeneities as well as variation in reservoir fluid properties.
The static and dynamic data were utilized to construct representative geological and dynamic models for the reservoir. The field development objective focused on maximizing the oil production and achieving 70% RF while minimizing the gas cusping, water conning and early breakthrough via super K interval.
Nine years production dynamic data were available from 6 oil producers in addition to well testing "14 wells", core "11 wells", MDT "17 wells" data during the appraisal phase. These data were used to quality control the initialization and history match phases. In preparation to the development options, the team included pressure support using water injection, lean gas injection, miscible gas injection, miscible WAG injection. The predicted reservoir performance of the super K oil reservoir indicated considerable gas production and high water production from the bottom water aquifer through super K interval in all the development options.
It was a big challenge to reduce the amount of gas production, water production, and early breakthrough for all development options. A new development option was introduced to perform peripheral miscible Hydrocarbon WAG injection accompanied with optimization of the wells and completion intervals locations for producers and injectors, as wells as WAG cycle to minimize the gas production from the gas cap, water production from the aquifer, and early breakthrough. This resulted in significant enhancement to plateau length, sweep efficiency, and recovery factor.
This paper provides the methodology followed to guide the development plan to fill in the uncertainty gap along with a detailed data acquisition and monitoring programs to better understand the reservoir behavior.
El Gazar, Ashraf Lotfy (Abu Dhabi Company for Onshore Petroleum Operations Ltd. (ADCO)) | Alklih, Mohamad Yousef (Abu Dhabi Company for Onshore Petroleum Operations Ltd. (ADCO)) | Sumaidaa, Saleh A. Bin (Abu Dhabi Company for Onshore Petroleum Operations Ltd. (ADCO)) | Al Shabibi, Tariq Ali (Abu Dhabi Company for Onshore Petroleum Operations Ltd. (ADCO))
This work illustrates field development plan and optimization studies conducted on a Middle-Eastern carbonate reservoir. The field lies in an onshore area where increasing urbanization is complicating the field development with regard to safety, accessibility, and drilling sites. The reservoir exhibits relatively fair to poor reservoir characteristics and variable oil water contacts due to faulting, suggesting the presence of 5 different reservoir compartments. A total of 10 wells had penetrated the reservoir out of which 8 wells tested oil and suggested a huge initial gas cap while 2 others penetrated water leg.
Six years of early production scheme (EPS, 4 producers, 1993 to 1998) data in addition to production testing, core (2 wells), MDT (3 wells), PVT (4 wells) data were gathered in order to identify the main uncertainties and test the feasibility of the full field development. EPS indicated production decline coupled with severe increase in GOR and water cut in some wells, after which the producing wells and facilities were P&A due to safety concerns and low productivity.
A number of parameters were addressed and optimized during the full field development plan. These include formation evaluation and modeling parameters based on EPS findings, the limited available data, and pressure support mechanism. Several development scenarios were constructed, consisting of various combinations of horizontal producers and injectors and considering natural depletion, WI, GI, and WAG scenarios targeting the proven reserves. The dynamic modeling suggests that an ultimate recovery of 70% can be achieved by the different injection scenarios. However, considering the complexity of the surrounding environment and the size of the prize, it is recommended that the field development would be economically viable for a period of 10 years under natural depletion, provided the most effective development strategy in terms of number, location, orientation and horizontal reach is adopted.
Alklih, Mohamad Yousef (ADCO - Abu Dhabi Co for Onshore Oil Operation) | Bin Sumaidaa, Saleh Awadh (ADCO - Abu Dhabi Co for Onshore Oil Operation) | El Gazar, Ashraf Lotfy (ADCO - Abu Dhabi Co for Onshore Oil Operation) | Knytl, Jan (ADCO - Abu Dhabi Co for Onshore Oil Operation) | Khan, Muhammad Kamran Ali (ADCO - Abu Dhabi Co for Onshore Oil Operation) | Abu Bakar, Aida Shafina (ADCO - Abu Dhabi Co for Onshore Oil Operation)
This paper presents a case study of developing a complex super k thin carbonate reservoir with a thin upper super permeable layer with a significant volume of oil, a gas cap and an active water drive in Abu Dhabi-UAE. The field lies in a coastal marine area covering mainland, natural and artificial islands as well as shallow and deep marine areas. The reservoir lies within a relatively low relief heterogeneous carbonate structural trap originally deposited within a complex depositional environment, characterized by lateral and vertical variations in reservoir rock and fluid properties.
Six years of production dynamic data are available from oil producers in addition to well testing and MDT data. The production is constrained by the presence of a high permeable streak just below the dense carbonate top seal and bounded by gas cap above and water below. This streak dominates the drainage of reservoir in such a way that the majority of the wells completed suffer from early apparent gas cusping and increasing water production.
The reservoir has been penetrated by vertical, deviated and horizontal wellbores. In relation to this, differences in production performance have been observed, specifically with respect to gas oil ratio and water cut. During the early development stage, three horizontal holes were drilled, however due to the difficulties of proper geo-steering of the horizontal hole placement within the thin oil column, two holes were placed in the gas cap and the third was placed in water. The main challenges of current and future development plans are the optimization of well design, placement and completion strategy to avoid the gas cap and transition zone.
This paper discusses the lessons learned from the ongoing development of the mentioned reservoir and the way forward for the future development phases.
Introduction and Background
The reservoir under development is a heterogeneous shallow dip carbonate ramp reservoir and considered to be oil bearing with gas cap and bottom water. The reservoir extends throughout a field that lies in a mixed coastal marine area covering land, sabkha, natural and artificial islands as well as shallow and slightly deep marine water (Fig. 1). The field is NE-SW elongated low relief gently dipping anticline with less than 0.5 degree at the crestal area.
Among the emerging technologies in the petroleum industry is the application of electro-kinetic phenomena to enhance oil recovery from tight heavy sandstone reservoir, which has been reported to yield technical and commercial success in some of the North American oil fields. The basic theory behind the stimulation effect is predicted to be the colloidal movement of pore lining clays that results in widening of pore throats and/or opening new flow tunnels. Nevertheless, few works have been performed on its applicability to water injection wells. This paper investigates the effect of electrokinetics on improving water injectivity in tight sandstone reservoirs.
Two sets of experiments were conducted. In the first set, the DC potential is varied and optimized during the water injection. In the second set, the DC potential is kept constant and the injection rate is varied to determine the hydrodynamic effect on clay movement. The core plugs and liberated clays were characterized through size exclusion micro-filtration and ICP-MS analysis. The Joule heating phenomena associated with electrokinetics is also studied during the entire injection period.
Results showed that several folds (up to 152%) apparent increase of core permeability could be achieved. Some of the experiments were more efficient in terms of dislodgement of clays and enhanced stimulation which is supported by produced brines analysis with higher concentration of clay elements. The results also showed larger quantity of clay elements in the produced brines in the initial periods of water injection, prior to the stabilization of differential pressure and electrical current, implying that the stimulation effect stops when the voltage gradient and flow rate values are no more able to remove additional clays. Additionally, fluid flow temperature measurements showed an increasing trend with the injection time and direct proportionality with applied voltages.
Introduction and Background
In general, the three phases of petroleum recovery processes are primary, secondary and tertiary oil recovery. The primary recovery phase is mainly driven by the natural energy present in the reservoir due to dissolved solution gas pressure, pressure from the overlain gas cap or due to the pressure from an active aquifer below the oil zone. In most cases, the natural driving mechanism is a relatively inefficient process and results in a low overall oil recovery (Ahmed, 2001). The lack of sufficient and consistent natural driving energy is compensated by supplementing with injection of water or gas (or a combination of both) which is the initiation of the secondary recovery phase. Due to several techno-economic factors, the most widespread secondary oil recovery process and responsible for most of world's oil production is the waterflood recovery (Willhite, 1986). Nevertheless, water injection may be associated with numerous hurdles related to fluid incompatibility, reservoir heterogeneity, early breakthrough through thief zones, permeability damage due to suspended particles and clay swelling.
Poor water injectivity is one of the problems that is often encountered by the operators especially in tight permeability formations (Pang and Sharma, 1997). This problem may further aggravate, when swelling type clays are present upon which pore throat blockage occur (Tchistiakov, 2000). This situation is often faced in clastic shaly sandstones. The swelling and release of clay particles from pore walls and their subsequent redeposition downstream in smaller pore throats would induce unexpected injectivity damage (Miniawi et al., 2007; Yi, 2001).