Rubio, Erismar (ADNOC Onshore) | Reddicharla, Nagaraju (ADNOC Onshore) | Dilsiz, Melike (ADNOC Onshore) | Al-Attar, Mohamed Ali (ADNOC Onshore) | Raj, Apurv (Weatherford) | Soni, Sandeep (Weatherford) | Sabat, Siddharth (Weatherford) | Isambertt, Jose (Weatherford)
This paper describes an efficient, accurate, and timesaving approach for setting well allowable using advanced and automated workflows in a digital oil field with more than 300 producing and injecting strings from multi-layered reservoirs having varied reservoir characteristics. This paper provides an insight on the usage of ADNOC shareholders guidelines, well characteristics, surface facility constraints, and integrated asset models to compute the well allowable rate.
An integrated asset operations model (IAOM) within a digital framework provides an automation of engineering approach where shareholder/reservoir management guidelines, in conjunction with a calibrated well and network models, are used to improve efficiency and accuracy of setting wells allowable. This process incorporates the interaction among various components, including wellbore dynamics (Inflow and outflow performance), surface network backpressure effect, and complex system constraints. "System Efficiency and Well Availability" factors as well as predicted well parameters such as GOR and watercut. This advance workflow computes the rate that can be delivered from each well corresponding to each guideline and constraint, thereby providing key inputs to various business objective scenarios for production efficiency improvement.
This automated "Setting Well Allowable" workflow, using an IAOM solution in a digital framework, has enabled the asset to identify true potential of wells and overcoming potential challenges of computational time saving while identifying opportunities. This automated validation workflows ensured usage of updated and validated well models, allowing effective use of the well test information and real time data for further analysis and sensitivities.
The use of the automated workflow has reduced the time to compute the well allowable rates and well technical rates by more than 50%. This workflow prevented engineers from performing tedious manual calculations on a well-by-well basis, therefore engineers focus on engineering and analytical problems rather than collecting data. Additionally, this robust engineering approach provides users with key information associated with a well's performance under various guideline index such as potential rates, well technical rate, minimum backpressure rate, rate to maintain drawdown/ minimum bottom hole pressure limit to ensure a homogenous reservoir withdraw to avoid pressure sink areas. This work process also highlights the wells with increased watercut (WC) and gas oil ratio (GOR), thus providing crucial information for deteriorating well performance. A short-term forecasting with diagnostic curve fitting and trend analysis enabled users to validate deliverability of allowable rates in a calibrated network model scenario, thereby incorporating potential surface constraints and facility bottlenecks.
The robustness of advanced and automated setting of well allowable workflow enables the operator to establish well performance with a solid engineering analysis base, and thereby unlocks key opportunities for saving cost, computational time and assuring short-term production mandate deliverables. This approach supports standardization of the work process across the whole organization.
Agnihotri, Praveen (ADNOC Onshore) | Pandey, Vikram (ADNOC Onshore) | Thakur, Parmanand (ADNOC Onshore) | Al Mansoori, Maisoon (ADNOC Onshore) | Rebelle, Michel (Total SA) | Smith, Steve (Baker Hughes, a GE Company) | Bhatt, Pranjal (Baker Hughes, a GE Company) | Zhunussova, Gulzira (Baker Hughes, a GE Company) | Hassan, Syed (Baker Hughes, a GE Company)
Holistic assessment of project economics and subsurface characterization provides a framework to handle challenging reservoirs. Capturing ranked uncertainties based on their impact on the project and meticulous working towards de-risking the project is key for the success of the entire project. Committing increased production from the field is dependent on proper evaluation of the reservoir.
This paper reviews characterization of a tight reservoir deposited in the intra-shelf Bab basin during lower Aptian time. Initial stage reservoir characterization is critical in formulating reservoir development plan and estimating a realistic assessment of rates and volumes for the field.
The target formation is a low-permeability (average permeability 0.5 mD) heterogeneous carbonate reservoir sitting directly above and adjacent to a producing carbonate reservoir. It is essential to understand communication between the zones. The pilot well is drilled with 225 ft of conventional core and quad-combo logs. Advanced logs such as resistivity image, cross-dipole acoustic, nuclear magnetic resonance, vertical interference test (VIT), formation pressure (including pressure transient data), and fluid samples were acquired. The main objectives of the evaluation program were to determine the formation pressure, collect representative oil sample(s), conduct vertical interference tests between the sub-zones and collect appropriate data for geomechanical and rock-physics characterization.
Thorough pre-job planning and cross-discipline cooperation during the operation provided high fidelity log data and interpretation of the data into a coherent result. This included integration of image data with vertical interference tests from the wireline formation tester (WFT) where barriers were confirmed. In addition, NMR permeability was matched and calibrated using pretest mobility measurements and formation pressure data was combined with full waveform advanced acoustic processing to explain the communication between the upper target zone and the lower producing reservoir. Advanced acoustic analysis helped to fully characterize the target formations with stoneley permeability, azimuthal anisotropy, and presence of fractures.
This paper demonstrates the importance of multi-disciplinary team effort in characterization of challenging reservoirs. It highlights the importance of holistic planning before the execution phase, and keeping a focus on the larger goal while executing individual aspect of a complicated project.
Formation evaluation measurements have evolved over decades and occasionally it benefits the industry to provide a review of how the latest logging measurements fit together in an integrated manner, for successful evaluation of a challenging reservoir.
Experiences gained from CO2 flooding to improve oil recovery worldwide indicates that considerable amount of remaining oil can be recovered with miscible CO2 injection under appropriate conditions. Though its performance in the heterogeneous Middle Eastern carbonate reservoirs has not been well demonstrated yet, it is most likely going to be the future hydrocarbons recovery process in Abu Dhabi after the successful implementation of the first miscible CO2-EOR pilot in 2009 by ADNOC Onshore. In 2016, ADNOC Onshore embarked on field scale implementation of CO2 injection; making it an integral part of the company's overall strategy to utilize CO2 as one alternative option to the expensive HC gas and address related key technical and business aspects.
The currently implemented CO2-EOR has been facing several complexities and challenges including, but not limited to, sustainability of CO2 supply, achieving miscibility conditions, optimization of production and injection, reservoir modeling issues, HSE risks, suitability of monitoring strategy, keeping the CO2 concentration levels within the existing plan design limits, maintaining the integrity of the facilities, associated operating costs and expansion of field development by CO2-EOR.
A number of mitigation plans and actions have been also put in place to ensure the smoothness of operations and therefore maintain the positive impacts of enhanced oil recovery by CO2 injection. Strong management support, multi-disciplinary data integration, continuous surveillance and pro-activeness are considered as the pillars for CO2-EOR success. This work aims to discuss the lessons learned from the ongoing development of CO2-EOR, after 2 years of implementation, and the way forward for the future development phases.
Syofyan, Syofvas (ADNOC Onshore) | Latief, Agus Izudin (ADNOC Onshore) | Ahmed Al Amoudi, Mohsen (ADNOC Onshore) | Al-Shamsi, Saif (ADNOC Onshore) | Hassan Ali Bal Baheeth, Asma (ADNOC Onshore) | Nestyagin, Andrey (ADNOC Onshore) | Ali Al-Shabibi, Tariq (ADNOC Onshore) | Banihammad, Basma (ADNOC Onshore) | Dasgupta, Suvodip (Schlumberger) | Mosse, Laurent (Schlumberger) | Yaseen Albuali, Abdulla (Schlumberger)
Carbonate reservoirs introduce challenge in providing accurate water saturation from conventional Archie equation. One of the reasons is due to the variability of the Archie cementation factor "m" because of complex and tortuous nature of these heterogeneous carbonates.
The study was performed by integrating core and log data from advance measurements to understand the root cause and range of the variability and an attempt to link sedimentology and diagenetic facies to petrophysical groups.
The Study focused on a carbonate reservoir with complex pore network. The formation resistivity factor (FRF) measurements were conducted with high-resolution sampling on a selected well. Each of FRF plug has associated porosity, permeability, thin sections, MICP, NMR and high-resolution dual energy micro CT scan. The m value from FRF is then plotted along the porosity-permeability plot. The capillary pressure parameters (entry pressure, slope, inflexion points) were extracted from MICP and relationship is plotted against m. Diagenetic facies described from the thin sections is compared versus m.
Principal component analyses was conducted to identify factors relating to m. The uncertainty on water saturation associated to variable parameter m was assessed using Monte Carlo analysis on multiple wells.
An advanced multi-frequency dielectric logging tool was run on couple of wells to provide variable water-phase tortuosity (MN) measurement. Specific analysis was performed to extract the variable m value from the measurement over limited zones, which has been derived from core "m" measurements.
Several wells located on the flank of the reservoir below water level were evaluated. Dean stark measurements were performed on a well and used to validate the saturation calculation.
It is obvious that the evaluated reservoir has high degree of heterogeneity as indicated by complex pore network with multi modal pore system as shown by the thin sections, MICP and plug CT Scan.
Pramudyo, Yuni (ADNOC Onshore) | Al Hosani, Mariam (ADNOC Onshore) | Al Awadhi, Fatima (ADNOC Onshore) | Masoud, Rashad (ADNOC Onshore) | Al Besr, Huda (ADNOC Onshore) | Nachiappan, Ramanathan (ADNOC Onshore) | Al Hosani, Khaled (ADNOC Onshore) | Al Bairaq, Ahmed (ADNOC Onshore) | Al Ameri, Ammar (ADNOC Onshore) | Bertouche, Meriem (Badley Ashton) | Foote, Alexander (Badley Ashton) | Michie, Emma (Badley Geoscience) | Yielding, Graham (Badley Geoscience)
Throughout the UAE and the wider region, several broadly E-W orientated structural lineaments are observed on seismic within the Cretaceous successions and are described as strike-slip faults. However, in the studied field, these features have not been readily observed in well data. Instead, networks of fractures and deformation features are present in core and borehole images. A study was carried out in an attempt to calibrate well and seismic data and to understand the relationship between the seismically-resolved faults and the fractures observed on core. This study focuses on a dataset from the north-east part of the field, which includes BHI images, cores, full 3D CT scans and conventional logs in four penetrations, three of which are horizontal, drilled through the faults; as well as 3D seismic data and relevant derived horizons and fault polygon interpretations.
The available data have been investigated in detail, with all structural features in core, circumferential CT scans and BHI images systematically classified using simple and reproducible descriptive schemes. All the structural features have been orientated using directional data from BHI. The understanding of the character and fill of the fractures observed in core has also been incorporated. A further calibration with seismic and integration of results with information from previous studies allowed a full description of the fracture networks, of their densities within and outside the potential fault corridors of the studied field, as well as an assessment of their potential for reactivation and their possible impact on localised formation compaction.
On the BHI images, several sub-vertical fractures have been identified, consisting mainly of mixed resistivity and resistive fractures, striking dominantly WNW-ESE. Particular zones along the wells have noticeably higher fracture densities, where features are organised in clusters; they are intercalated with zones where fractures are rarer. The clustering of fractures within fracture corridors are believed to be fault-related, subvertical and tabular fracture clusters that traverse an entire reservoir unit vertically and extend for several hundreds to thousands of feet laterally. These zones are believed to represent fracture corridors, which correlate with the structural lineaments observed on seismic.
The fracture corridor network in the study area shows a variable deformation signature at the different scales of observations, but consists mainly of sub-vertical (dominantly >60°) deformation bands (
Al Hosani, Mariam Ahmed (ADNOC Onshore) | Masoud, Rashad Mohamed (ADNOC Onshore) | Al Beshr, Huda Abdullatif (ADNOC Onshore) | Latif, Mohd Anwar (ADNOC Onshore) | Al Hammadi, Shamma Jasem (ADNOC Onshore) | Khalil, Ihab Nabil (ADNOC Onshore) | Al Bairaq, Ahmed Mohamed (ADNOC Onshore) | Al-Ameri, Ammar Faqqas (ADNOC Onshore) | Nasreldin, Gaisoni (Schlumberger) | Ni, Qinglai (Schlumberger) | Rodriguez-Herrera, Adrian (Schlumberger) | El Mubasher, Husham Kamal El Din (Schlumberger) | Corona, Mauricio (Schlumberger) | Sinha, Ravi Kumar (Schlumberger) | Subbiah, Surej Kumar (Schlumberger) | Hussein, Assef Mohamad (Schlumberger) | Karamalla, Babikir Mubarak (Schlumberger)
The growing appreciation of the effects of production-induced stress changes on reservoir performance has concentrated the minds of many people on the potential value of using geomechanical modelling to predict and quantify these effects for making life-of-reservoir decisions—relating to compaction mitigation and completing new wells.
This paper is concerned with well integrity analyses for compacting reservoirs—focusing specifically on a new area of predictive geomechanical modelling realised using the finite element method. The innovative workflow presented offers significant improvements and, for the first time, captures some of the realities of the construction process. It takes into consideration both the formation and completions by integrating 3D near-wellbore geomechanical modelling with cementing simulations and casing integrity analyses. Specifically, casing eccentricity and cement contamination data are taken from numerical cementing simulations carried out to re-create the conditions in wells with different trajectories. Moreover, formation mechanical properties, pore pressure and stress states from the time of drilling till the end of a simulated production schedule are taken from a calibrated field-scale geomechanical model and subsequently used to create high-resolution 3D near-wellbore geomechanical models.
The case study presented in this paper concerns a giant onshore field with multiple stacked reservoirs—containing a variety of hydrocarbons and experiencing different levels of depletion. The main interest is in conducting comprehensive casing and cement integrity assessments—particularly for wells located in compacting reservoir zones. A persistent challenge for geomechanical modelling and prediction is the availability of calibration data. This paper reduces uncertainty by presenting results concerning sensitivity analyses for a variety of completion conditions—including different levels of casing eccentricity, different degrees of cement contamination and different extents of casing corrosion.
Mawlad, Arwa Ahmed (ADNOC Onshore) | Mohand, Richard (ADNOC) | Agnihotri, Praveen (ADNOC Onshore) | Pamungkas, Setiyo (ADNOC) | Omobude, Osemoahu (ADNOC) | Mustapha, Hussein (Schlumberger) | Freeman, Steve (Schlumberger) | Ghorayeb, Kassem (American University of Beirut) | Razouki, Ali (Schlumberger)
Challenges associated with volatile oil and gas prices and an enhanced emphasis on a cleaner energy world are pushing the oil and gas industry to re-consider its fundamental existing business-models and establish a long-term, more sustainable vision for the future. That vision needs to be more competitive, innovative, sustainable and profitable. To move along that path the oil and gas industry must proactively embrace the 4th Industrial Revolution (oil and gas 4.0) across every part of its business. This will help to overcome time constraints in the understanding and utilization of the terabytes of data that have been and are continuously being produced. There is a clear need to streamline and enhance the critical decision-making processes to deliver on key value drivers, reducing the cost per barrel, enabling greater efficiencies, enhanced sustainability and more predictable production.
Latest advances in software and hardware technologies enabled by virtually unlimited cloud compute and artificial intelligence (AI) capabilities are used to integrate the different petro-technical disciplines that feed into massive reservoir management programs. The presented work in this paper is the foundation of a future ADNOC digital reservoir management system that can power the business for the next several decades. In order to achieve that goal, we are integrating next generation data management systems, reservoir modeling workflows and AI assisted interpretation systems across all domains through the Intelligent Integrated Subsurface Modelling (IISM) program. The IISM is a multi-stage program, aimed at establishing a synergy between all domains including drilling, petrophysics, geology, geophysics, fluid modeling and reservoir engineering. A continuous feedback loop helps identify and deliver optimum solutions across the entire reservoir characterization and management workflow. The intent is to dramatically reduce the turnaround time, improve accuracy and understanding of the reservoir for better and more timely reservoir management decisions. This would ultimately make the management of the resources more efficient, agile and sustainable.
Data-driven machine learning (ML) workflows are currently being built across numerous petro-technical domains to enable quicker data processing, interpretation and insights from both structured and unstructured data. Automated quality controls and cross domain integration are integral to the system. This would ensure a better performance and deliver improvements in safety, efficiency and economics. This paper highlights how applying artificial intelligence, automation and cloud computing to complex reservoir management processes can transform a traditionally slow and disconnected set of processes into a near real time, fully integrated, workflow that can optimize efficiency, safety, performance and drive long term sustainability of the resource.
Noufal, Abdelwahab (ADNOC Upstream) | El Wazir, Zinhom (ADNOC Onshore) | Al Madani, Noura (ADNOC Onshore) | Shinde, Ashok (Baker Hughes, a GE company) | Perumalla, Satya (Baker Hughes, a GE company) | Aldin, Munir (MetaRock) | Govindrajan, Sudarshan (MetaRock) | Gokaraju, Deepak (MetaRock)
Heterogeneous nature of the Cretaceous carbonate reservoirs in Abu Dhabi increases there complexity to attain efficient characterization and hence development. During depletion, reservoir pressure reduction results in unequal increase of vertical and horizontal effective stresses and thus an overall increase in the effective mean and shear stresses on the reservoir pore structure. At reservoir pressures below a critical value (obtained via laboratory testing or post failure field analysis), the reservoir compacts at accelerated rates. Compaction and its associated reduction in reservoir pore volume leads to rapid loss in permeability, generation of fines and wellbore stability issues (e.g., casing collapse). Assessing the magnitude of these changes require laboratory measurements of rock compressibility (grain, bulk and pore compressibilities), and concurrent evaluations of reduction of pore volume, porosity and permeability as a function of reservoir pressure needs to be appropriately simulated in-situ stress conditions. Poor appreciation of the rock compressibility mechanics and its robust dependence on stress path (e.g., hydrostatic- and/or uniaxial strain compression) in addition to depletion rate may result in substantial cost.
The core intervals are selected to capture the lateral and vertical heterogeneity encountered in the studied reservoirs. The test program was designed to create a material model to capture the rock response to potential reservoir pressure changes. Single Stage Triaxial tests at multiple confining stresses were conducted to judge the shear failure. Tests recommended for evaluation and assessment of reservoir compaction are Uniaxial-strain compression (far-field compaction), triaxial compression (near wellbore), Hydrostatic (define the compaction cap) and constant stress-path. Additional tests were carried to characterize the poro-elastic response of reservoir rock and the stress-dependent permeability.
A combined failure envelope (defining shear (dilatant) and compaction ("Cap") for compactable sediments) of the rock was generated by integrating the results from Single stage Triaxial tests (Shear failure envelope), hydrostatic compression tests and UPVC tests (Compaction failure envelope). For field applications, it is useful to provide a visualization of the pre-production-state in-situ stress conditions, and the possible stress path trajectories of the reservoir, as a function of reservoir depletion. Such a failure envelope was generated for all the different lithofacies encountered across the field. The characterized material model enables us to assess and predict the risk of shear/compaction deformation associated with the reservoir pressure changes (considering field stress path). Using this display, the level of depletion resulting in accelerated compaction can be identified through laboratory testing.
The introduced workflow presents a comprehensive geomechanical characterization program for such complex carbonate reservoir. This utilizes a systematic approach to generate field wide understanding of rock response to depletion and injection. It can also act as a guide to address the compaction-based challenges faced in other reservoirs of Abu Dhabi.
Tiar, Saloua (ADNOC Onshore) | Rubio, Erismar (ADNOC Onshore) | Albelazi, Abobaker (ADNOC Onshore) | Ofodile, Azubuike (ADNOC Onshore) | Abdulsallam, Fouad (ADNOC Onshore) | Al Karra, Mohamed (ADNOC Onshore) | Al-Khatib, Haitham (ADNOC Onshore) | Al Attar, Mohamed (ADNOC Onshore) | BenAmara, Abdel (Silverwell Energy) | Faux, Stephen (Silverwell Energy) | Makin, Graham (Silverwell Energy)
The dual completion technique is considered very attractive by major oil companies as it offers significant CAPEX saving while maximizing oil recovery. Even though the first dual completion installation was in the 1960s, applications have been limited since it requires especial completion equipment, complicated run in/out hole procedures and challenging artificial lift implementation. Dual completions are also complicated by a lack of production control equipment. All these factors constrain the deployment of this potentially profitable completion technique worldwide.
API 19G9 advises that dual-string gas lift is problematic and often ineffective. It is difficult, or even impossible to effectively producing both completed zones in a dual-string gas-lifted well, due to the complexity of controlling gas injection using conventional pressure operated valves.
The string dedicated to the formation with the lowest productivity and reservoir pressure tends to divert the gas from the other string. Additionally, fluctuating casing pressure, unpredictable temperature gradients due to the proximity of the two strings, and inability to individually controlling the injection rates to each string makes simultaneous production optimization of these wells extremely complex.
The majority of ADNOC Onshore dual completion wells are equipped with gas lift mandrels in only one of the strings, limiting the production from the naturally flowing string when water breaks through. Few wells in ADNOC Onshore have both stings on Gas lift. For these that do, the optimization of the amount of gas required for each zone is difficult and requires multiple wireline operation to change orifice sizes, causing increased operational risks.
To overcome the production and operations constrains of existing gas lift practice in dual completion wells; the authors developed a dual string well design employing digitally controlled integrated gas lift valves. This design enables the adjustment of the gas lift injection rates for each of the strings without the need of rig-less intervention. Furthermore, the desing allows the simultaneous recording of downhole temperature and pressure at gas injection depth in each producing string.
This paper describes the technical and economic evaluation of the pilot implementation of DIAL technology in dual completions across ADNOC Onshore, covering the candidate selection criteria, integrated evaluation of the well performance & surface debottlenecking scenarios, completion design considerations, best practice Installation and data integration system that ensure achieving a set of success criteria and targeting additional 20% extra production per well.
This Worldwide first implementation of digital gas lift production optimization system in a dual string well, will be a game changer in the industry, enabling efficient production and enhanced recovery from both reservoirs within the same well. If successful, it is expected to achieve an additional production gain while reducing 30 % of the gas consumption.
Singh, Maniesh (ADNOC Onshore) | Dey, Swapan Kumar (ADNOC Onshore) | Farooq, Umer (ADNOC Onshore) | Radwan, El Sayed (ADNOC Onshore) | Rajwade, Sachin (Weatherford Laboratories) | Tombokan, Xenia (Weatherford Laboratories) | Mendoza, Rafael (Weatherford Laboratories) | Hannon, Loay (Weatherford Laboratories) | Watson, Rayvan (Weatherford Laboratories)
The estimation of bulk volume of irreducible water (BVI) is one of the earliest and the most widely used applications of NMR logging using either a fixed T2 cutoff value or Spectral BVI. NMR BVI assumes that bound fluid resides in small pores and producible free fluids (FFI) resides in large pores where the pore throat and pore body sizes are often related. As T2 distribution is related to a pore body size, a T2 cutoff can partition BVI & FFI.
In Carbonates there is no clear relationship of pore throat size to pore body size, thus measuring BVI T2 cutoff per rock type becames important although challenging. This paper covers the importance of following correct laboratory procedures, quality assurance of laboratory experimential data, and innovative methods to determine reliable T2 cutoff which otherwise are very low and not practical to apply in the NMR log domain.
NMR analysis was performed with a 2 MHz field instrument using a CPMG sequence and sufficient echo trains to acquire reliable T2 distribution. T2 cutoff was determined on core samples with a wide range of porosity, permeability, and rock types. Core samples were analyzed for T2 distribution at elevated temperature and pressure. First the cores were saturated with formation brine to 100% Sw, followed by desaturation using the porous plate pressure equilibrium method to Swirr. Initially, desaturation with gas provided very low T2 cutoffs; desaturation steps were repeated using a lab oil with reservoir property to investigate its positive impact on the T2 cutoffs and to use in the NMR log domain.
The T2 curve of the fully saturated plugs with brine shows a shift towards the shorter T2 time. Determination of T2 cutoff from the gas-brine system in the laboratory results in lower T2 cutoff values approximately 15 to 50 msec. This is due to the lower T2 response at the Swirr state from the combined affect of pores still partially saturated with brine and gas diffusivity affects. When desaturating with lab oil, the NMR response results in more reliable T2 cut-off of 55 to 100 msec.
NMR T2 cutoff for BVI using the oil-brine system has been determined using two methods, a conventional method where T2 cutoff is determined where the cumulative T2 value of the Sw at 100% brine equals the cumulative T2 value of the Swirr. The other method is where the T2 cutoff separates major peaks of bound and free fluid in the incremental T2 response. The conventional method posed a challenge in picking correct T2 cutoff due to various complexity as outlined in the paper. The latter method provided more reliable and better control on picking T2 cutoff to apply in the NMR log domain.