Field presented here is located in offshore Abu Dhabi, consisting of multi-stacked reservoirs with different fluid and reservoir properties. In this paper, field development plan of one of reservoir has been presented which was initially planned to be developed with pattern water injection by more than 50 horizontal wells penetrating all the ten oil bearing layers from 9 well head towers. Reservoir consists of under-saturated oil with low gas-oil ratio and low bubble point. Initial 2 years of production was considered as Early Production Scheme (EPS period), during which significant amount of early production data consisting of downhole pressure measurement, time-lapse MDT, vertical interference data, PLT have been collected. Based on EPS data simulation model has been updated. Simulation fits well with the observed pressure gauge and time-lapse MDT data. Updated model gives good prediction for a year of blind test data (including saturation, MDT and porosity) collected from different wells several kilometers away from current development area reflecting a high level of confidence in areal and vertical connectivity representation. Considering other reservoir uncertainties different Development plans have been screened using updated model in order to improve recovery factor and economics. Based on development plan screening study, optimized development option has been chosen for Full Field Development.
Raghunathan, Murali (ADNOC - Al Dhafra Petroleum Company) | Alkhatib, Mohamad (ADNOC - Al Dhafra Petroleum Company) | Al Ali, Abdulla Ali (ADNOC - Al Dhafra Petroleum Company) | Mukhtar, Muhammad (ADNOC - Al Dhafra Petroleum Company) | Doucette, Neil (ADNOC - Al Dhafra Petroleum Company)
A novel workflow was developed to select an optimal field development plan (FDP) which accounts for a number of associated uncertainties for an oil Greenfield concession that has a limited number of wells, production data and information. The FDP was revisited and updated to address the additional data acquired during the field delineation phase. The study in Ref-1 demonstrates the comprehensive uncertainty analysis performed and the resulting optimized FDP. The FDP was developed to minimize the economic risk and uncertainty. Further field delineation activities have revealed a north and south extensions with an increase in hydrocarbon accumulation by 115%. A reservoir dynamic model was updated because of the increase in HC and input data from 17 wells. A workflow has been created with a suitable development option to consider the recently appraised areas, which are: - Updated saturation height functions (SHFs) which improve the match between newly drilled wells and water saturations logs - Updated reservoir models which were based on well tests and new analytical interpretations - History matching well test data with new acquisition data - Optimized field development options, that cover additional areas - Inputs to reservoir surveillance plan Be implementing following an extensive analysis the most robust development concept was selected and will now in the field.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
Subsea processing using subsea separation and pumping technologies has the potential to revolutionize offshore oil and gas production. Between 1970 and 2000, millions of dollars were spent to develop subsea separation and pumping systems. But because of unresolved technical issues, along with a lack of confidence and clear understanding of the costs and benefits, industry did not rush to deploy the technology on a commercial basis. However, as the industry has moved into remote deep and ultradeep water, various degrees of subsea processing are becoming more common. In deep water, the technology can enable hydrocarbon recovery from small reservoirs that are subeconomic by conventional means, making small fields economically viable and large fields even more profitable.
The estimation of total hydrocarbons (HCs) in place is one of the most important economic challenges in unconventional resource plays. Nuclear magnetic resonance (NMR) has proven to be a valuable tool in directly quantifying both hydrocarbons and brines in the laboratory and the field. Some major applications of NMR interpretation include pore body size distributions, wettability, fluid types, and fluid properties. However, for tight formations, the effects of the factors on NMR relaxation data are intertwined. One purpose of this study is to review the interpretation of NMR response of HCs in a tight rock matrix through illustrated examples.
When comparing NMR data between downhole wireline and laboratory measurement, three important elements need to be considered: 1) temperature differences, 2) system response differences, and 3) pressure (mainly due to the lost gasses.) The effect of temperature on HCs would be presented with experimental results for bulk fluids. Whereas, the effect of pressure is investigated by injecting gas back into rock matrix saturated with original fluids. The experiments were performed within an NMR transparent Daedalus ZrO2 pressure cell which operates at pressures up to 10,000 psi.
The results show that, at a temperature and pressure, NMR responds to a fraction of HCs which is volatile enough to be observed as an NMR relaxation sequence. The invisible fraction of HCs to NMR sequence at ambient condition can be up to 20% of the total extractable HCs. Molecular relaxation is impacted by fluid viscosity, pore size, and surface affinity. In other words, the fluid with higher viscosity (either due to temperature or gas loss), presenting in smaller pore, or highly affected by the pore surface, will relax faster, and would be partially invisible to NMR, especially in the field. This is critical to the interpretation of NMR response for liquid rich source rocks, in which all of the above molecular relaxing restrictions can be found. Thus, engineers can underestimate movable HCs by using routine core analysis data.
Galvan, Irma Galvan I. I. (Global Tubing LLC) | Jimenez, Jose Jimenez J. M. (Halliburton) | Ulloa, Joel Ulloa J. (Halliburton) | Wheatley, Edward Wheatley E. J. (ADNOC Offshore) | McClelland, Garry McClelland G. (Global Tubing LLC)
With the aim of long-term sustainable production in the Persian Gulf, wells are being developed on artificial islands to maximize reservoir contact using extended reach drilling technologies with liner completions. This drilling strategy has many advantages and efficiencies, albeit, it results in complex 3-D well trajectories which challenge service operations throughout the well's life cycle. The ability to perform interventions in these wells with challenging laterals using Coiled Tubing (CT) is critical for achieving field development goals.
With well cleanouts and stimulation as the primary scope of work, a CT string was custom-engineered to maximize reach capabilities and injection rates, in well trajectories of up to 4.5:1 MD/TVD ratios that extend up to ~20,000-ft laterals through the reservoir. The challenging operating requirements incorporate several constraints, including accessibility of +30,000-ft target depths, minimizing the use of high cost extended reach tools, and achieving injection rates of at least 5 BPM, all within acceptable pressure limits to maximize CT service life, without exceeding surface equipment capabilities available in the area.
An iterative CT design methodology that incorporated the use of patented CT manufacturer strip technology, extensive tubing forces and hydraulics analyses, traction-force generating tool capabilities, fatigue simulations, and improved operation practices, enabled safe and successful deployment of 70-T (155,000-lbs) 2.375-in CT strings with 31,500-ft continuous length on the artificial islands.
CT strings reached target depths, with the bottom-hole assembly (BHA) generating 7,500-lbf of traction force in the most difficult wells, while delivering up to 5 BPM injection rates during the stimulation operations. These extended reach CT strings are the largest (by weight) ever produced and deployed on the artificial islands, which enabled the well operator to maximize well performance and productivity in ultra-long lateral wells.
This paper demonstrates the extensive design process to provide support and custom-engineer CT strings to perform complex operations - including matrix stimulation, mechanical isolation, scale inhibition, water control, and well cleanouts. Analysis of the field data, and performance of the strings will also be discussed to demonstrate increased efficiencies achieved by the well operator.
As future wells are being designed with greater laterals, further development in downhole tools technology will allow the deployment of +35,000-ft CT in continuous length to economically and efficiently achieve extended reach CT operational goals in the field. Engineered solutions for 2.375-in CT over 36,500-ft are currently in the design stage. These strings are expected to surpass the 73 T (tube only) weight -becoming a future milestone for CT interventions.
ADNOC awarded a $1.36-billion dredging, land reclamation, and marine construction contract to the UAE’s National Marine Dredging Company (NMDC) for the construction of multiple artificial islands in the first phase of development of the Ghasha Concession. The Ghasha Concession comprises the Hail, Ghasha, Dalma, Nasr, and Mubarraz offshore sour gas fields. Under the terms of the contract, NMDC will construct 10 new artificial islands and two causeways, and it will expand an existing island (Al Ghaf). The project is expected to take 38 months to complete and will provide the infrastructure required to further develop, drill, and produce gas from the sour gas fields in the Ghasha Concession. ADNOC said in a statement that the artificial islands will, among other things, provide greater flexibility for extended-reach drilling compared to offshore rigs.
The Ghasha Concession comprises the Hail, Ghasha, Dalma, Nasr, and Mubarraz offshore sour gas fields. Under the terms of the contract, NMDC will construct 10 new artificial islands and two causeways, and it will expand an existing island (Al Ghaf). The project is expected to take 38 months to complete and will provide the infrastructure required to further develop, drill, and produce gas from the sour gas fields in the Ghasha Concession. ADNOC said in a statement that the artificial islands will, among other things, provide greater flexibility for extended-reach drilling compared to offshore rigs. They will also eliminate the need to dredge more than 100 locations for new wells.
Takabayashi, Katsumo (INPEX) | Shibayama, Akira (INPEX) | Yamada, Tatsuya (ADNOC Offshore) | Kai, Hiroki (INPEX) | Al Hamami, Mohamed Tariq (ADNOC Offshore) | Al Jasmi, Sami (ADNOC Offshore) | Al Rougha, Hamad Bu (ADNOC Offshore) | Yonebayashi, Hideharu (INPEX)
This study aims to improve asphaltene-risk evaluation using long-term data. Temporal changes in asphaltene risks with gas injection were evaluated. In reservoirs under gas injection, the in-situ fluid component gradually changes by multiple contact with the injected gas. Those compositional changes affect asphaltene stability, causing difficulty in risk prediction using asphaltene models. This study aims to reduce the risk uncertainty depending on operational-condition changes.
Periodic upgrading of asphaltene models is essential for understanding the time-dependent changes of asphaltene risks. In a previous study, the asphaltene risk was evaluated for an offshore oil field in 2008 using the cubic-plus-association equation-of-state (EOS) models and using all the available data at the time. Additional experimental data were subsequently collected for a gas-injection plan. An additional study was performed that incorporated and compared the data sets.
According to the previous study recommendation, additional asphaltene laboratory studies were conducted using the newly collected samples. All the asphaltene-onset pressures (AOPs) detected in the new samples were higher than those found in the previous study. A large difference was observed between the past and recent AOPs in the lower reservoir even though the samples were collected from the same well. The asphaltene-precipitation risk increases considerably because the new study detected AOP at the reservoir temperature, whereas no AOPs were detected in the previous study. The difference may be attributed to saturation-pressure increase. Next, the numerical asphaltene models were revised; the re-evaluated asphaltene-risk estimations were higher in the lower reservoir and slightly higher in the upper reservoir than the past ones. The reference sample fluids were collected from two different wells with different asphaltene and methane (C1) contents. The reliability of the new asphaltene laboratory results was increased by applying multiple data interpretation. Thus, the difference between the past and recent results can be attributed to fluid alteration with time. On the basis of the analysis in this study, the risk rating was updated to slightly higher than in the previous evaluation, emphasizing the importance of regular monitoring of asphaltene risks.
This study provides valuable findings of time-lapse evaluation of asphaltene-precipitation risks for a reservoir under gas injection. The evaluations currently conducted in the industry are snapshots of instantaneous risks. Through the entire field life, the risks have varied depending on the operating conditions. This study demonstrates that risk estimates can change in a unique field with identical work flow by analyzing data collected at different times. Finally, this study demonstrates the importance of time-dependent reservoir-fluid properties.