One method of reducing the recognized threat of global warming is using continued sequestration of anthropogenic "greenhouse gases," such as carbon dioxide (CO2). Sedimentary basins are present globally and, because of the omnipresent nature of deep, regional-scale aquifers within them, they can be considered as potential sites for disposal and sequestration of CO2. Successful implementation requires identifying and considering fundamental concepts to help ensure that CO2 is stored in the aquifers effectively. The ideal scenario involves migrating CO2 from injection wells to remote storage sites using the aquifer, helping ensure its isolation from the atmosphere for a considerable length of time. In addition to the scientific and technical aspects of sequestration research, the practicality of the concept should be considered, including evaluating the maximum possible volume of CO2 that can be stored at global and regional levels as well as the safety and economic feasibility of the process. This study discusses examples to help provide an in-depth, practical understanding of this concept.
The study combines a full-physics commercial simulator with an effective uncertainty and optimization tool. The sequestration phenomenon is then modeled to investigate the significance and effect of the essential parameters on well performance while also considering thermal and geochemical effects. The process assesses the injection of CO2 containing tracers for 25 years, followed by shutting in the injectors and modeling the status of CO2 for the next 225 years. While CO2 is injected into an aquifer, the molecular diffusion of CO2 in water is modeled. The modeling of the thermal effects attributable to the injection of CO2 is important because the chemical equilibrium constants have a functional thermal dependency.
For reservoir management, the evaluation and effective management of uncertainties are as important as managing the well-level parameters. For this study, essential reservoir and well parameters are identified, and sensitivity and optimization processes are performed on them; the tornado charts in this paper illustrate the significance and effect of each parameter. Thermal and geochemical effects are shown to play vital roles in the sequestration process.
This study outlines the significance of essential parameters associated with the overall success of the CO2 sequestration in aquifers using in-depth uncertainty and optimization analysis, and it considers the influence of thermal and geochemical effects.
Stewart, Robin (Halliburton) | Osman, Tarek (Halliburton) | Reda, Tamer (Halliburton) | Al-Ajmi, Abdullah (Kuwait Oil Company) | Al-Rushoud, Abdulaziz (Kuwait Oil Company) | Gohain, Ashis (Kuwait Oil Company) | Khatib, Faiz (Kuwait Oil Company) | Al-Haj, Hussain (Kuwait Oil Company) | Al-Naqa, Faisal (Kuwait Oil Company) | Al-Mutawa, Faisal (Kuwait Oil Company) | Al-Gharib, Majed (Kuwait Oil Company) | Shinde, Hrishikesh (Kuwait Oil Company) | Al-Mekhalef, Alanoud (Kuwait Oil Company)
Conventional coring does not provide core samples that are characteristic of the original formation condition. Thus, pressurized coring is required to capture samples that represent the in-situ composition of gases and liquids; pressure, volume, and temperature (PVT) data of the fluids, and porosity, permeability, and wettability, which are critical to reservoir interpretation and development. A customized high-performance water-based mud (HPWBM) was used successfully where prior attempts with conventional water-based mud (WBM) had failed.
The key well challenges included wellbore instability with caving shale and depleted reservoir sands. Previous attempts to retrieve pressurized core using conventional WBM proved unsuccessful because of the early activation of the pressurized capture mechanism caused by an accumulation of wellbore and mud solids linked to insufficient hole stability. A HPWBM containing liquid additives was customized to minimize solids content while stabilizing the shales and to minimize the differential sticking potential in the depleted reservoir. The formulation was finalized, based on laboratory testing, to optimize the bridging and inhibition package for the formations drilled.
Drilling and logging were successfully completed with no incidents; the fluids parameters were maintained to effectively clean the hole while controlling equivalent circulating density (ECD) through minimizing solids in the mud. The combination of salinity and liquid additives used minimized the total solids of the mud while effectively stabilizing the wellbore, which helped to reduce the premature activation tendency of the catcher system of the pressurized coring tool.
Pressurized cores were successfully retrieved with in-situ conditions and analyzed on-site, maintaining a pressure equivalent to the pore pressure. The core samples were retained in their native state for future studies. There was no nonproductive time (NPT) related to wellbore instability, and differential sticking was avoided by the customized bridging across the depleted reservoir. The successful collection of data enabled improved reservoir modeling.
This paper discusses the design of the HPWBM system, along with its technical features and benefits, which helped to successfully complete the first global 12 ¼-in. pressurized coring application. The customized HPWBM provided good shale inhibition, low solids and excellent lubricity, and eliminated the need for conventional shale stabilizing materials, which could have interfered with the capture of the pressurized core.
Narwal, Tushar (Petroleum Development Oman) | Riyami, Yaqoob (Petroleum Development Oman) | Rashdi, Mansoor (Petroleum Development Oman) | Abri, Zahir (Petroleum Development Oman) | Sariri, Aisha (Petroleum Development Oman) | Benchekor, Ahmed (Petroleum Development Oman) | Hadhrami, Abdullah (Petroleum Development Oman) | Dsouza, Rylan (Petroleum Technology Company) | Brodie, Alan (Petroleum Technology Company) | Strom, Kyle (Halliburton)
In South Oman, PDO is producing from high Sour Fields (H2S 1-10%) with high reservoir pressures ranging from 50,000 to 100,000kpa for more than 20 yrs. Operating these high sour wells comes with huge challenges and risks, which can easily get escalated to very high levels in case of any integrity issues with the wells. These situations not only provide significant exposure to expensive and risky well interventions but also pose threats to production due to Simultaneous Operations (SIMOPS) issues.
The authors describe case studies where team was exposed to these challenging situations due to integrity failures in two such wells. New technologies were implemented which resulted in restoring the well integrity in a very cost effective manner (cost savings worth millions) and also reduced the HSE risks on the nearby operations. As a result, production was safeguarded (3-4% of Station Capacity) by allowing drilling of new wells and oil deferment from existing wells in the nearby area was avoided.
An integrated asset modeling (IAM) approach was used to evaluate a reinvigorated facilities configuration for a mature giant oilfield offshore Abu Dhabi. The field has produced for 50 years through steel jacket-based "supercomplex" facilities. A new artificial islands-based strategy has been envisioned to cater to higher production requirements, replace ageing facilities approaching their design lives, and debottleneck the water and gas handling capacity.
Commercially available reservoir simulation software was used to develop the integrated reservoir simulation model. The IAM fully couples three compositional simulation models for each reservoir unit to an extensive pipeline network and incorporates the timely rerouting of existing facilities to the new processing centers. Eventually, the "supercomplexes" only receive wellstream fluids from the existing wellhead towers (WHTs) network and redirect production to the new centralized processing island where it goes through a three-phase separation. Recent pressures and production data were used to calibrate the IAM.
The IAM was successfully used to evaluate the impact of the new surface layout on production. The production profiles from the standalone models, based on constant terminal node pressure at the wellheads, were compared to the IAM profiles. Pragmatic guidelines were defined to obtain representative profiles from the standalone models. Additionally, the IAM was used to guide the future facilities design by addressing the sizing of the water and gas handling capacity and identifying future surface bottlenecks. Moreover, the compositional IAM allowed quantifying the H2S content in the stream. The reservoirs being drained have varying levels of H2S, and prediction of the gas sourness is an important parameter for separator and pipeline design and for determining the sale gas value. Finally, the IAM had flow assurance applications, such as assessing the changes in pipeline temperature. Indeed, as the field matures, wells are forecasted to produce more water, raising the field water cut from the current 7% to 20% in the next 10 years. This increase in water cut would increase the pipeline temperature. The IAM allowed forecasting of the steady-state pipeline temperature to ensure existing pipelines are operated within specifications and to help design future flowlines.
Lost circulation is a recurring and costly challenge for the oil and gas industry. Losses range from seepage to total and financial effects, including nonproductive time and remedial operational expenses, which can increase potential risks to the operator. To address this issue, a tunable cement-based lost circulation treatment solution has been developed that is most suitable for partial to total losses, particularly when particulate-based solutions are not effective; the solution is primarily intended to cure losses while drilling. Unlike conventional lost circulation materials (LCMs) that cure losses by mechanical bridging of particles, the thixotropic cement solution's effectiveness arises from its unique chemical composition, which is ideal when flow paths are too large to be plugged by particles.
The new lost circulation treatment solution is thixotropic with a density range of 10 to 15 lbm/gal working in temperatures up to 250°F. The formulation can be mixed with fresh water, seawater, or seawater with up to 14% NaCl. It is designed and tested in accordance with API RP 10B2 (2013) procedures for thickening time (TT), compressive strength, static gel strength, fluid loss, and rheology. During the TT on-off-on test, the formulation builds gel strength when shear is reduced and regains fluidity when shear is reapplied.
The formulation developed rapid static gel strength and an early compressive strength up to 500 psi. The reversible gelation behavior is demonstrated through multiple shear on-off cycles. This solution is operationally convenient to apply because it can be pumped through the bottomhole assembly (BHA), thus reducing trip times. Because of its acid solubility, it can be used across production zones.
The unique properties of gaining rapid gel strength reversibly and a good compressive strength render this solution effective for treating a wide range of lost circulation events during drilling. A wider density window might minimize the potential risk of inflow when treating losses.
Marzouqi, Mohamed Al (ADNOC) | Saputelli, Luigi (ADNOC) | Abdou, Medhat (ADNOC) | Mohan, Richard (ADNOC) | Pandian, Senthil Murugan (ADNOC) | Hammadi, Maryam Al (ADNOC) | Khan, Muhammad Navaid (ADNOC) | Cumming, John (Halliburton) | Pires, Joshua (Halliburton) | Escorcia, Alvaro (Frontender)
The objective of this work is to enable the collaboration of multiple disciplines in the performance reviews of reservoirs while establishing a culture of variance reduction and sustainable consistency in results delivery. This effort focuses on the performance management reviews of very large carbonate reservoirs where the number of wells and producing zones overwhelm engineers and organizations with data volume and complexity due to areal and vertical heterogeneity.
A novel Reservoir Performance Review (RPR) solution has been implemented across various offshore reservoirs units. RPR initiates all asset activities during reservoir performance reviews and allows the tracking of actions over the life of the reservoir.
RPR leverages data analytics to automatically compute reservoir health key performance indicators that allow prioritization of the technical work, extract and transform data from multiple data sources, deliver performance dashboards with diagnostic plot standardized across all assets and users providing an archive of information and knowledge from past reservoir performance reviews.
RPR leverages business process management and integrated visualization to assist in the identification and recording of opportunities, risks and actions, while providing control and management of the business processes.
The solution offers an innovative way to collaboratively gather, validate, analyze reservoir performance across the asset on a sustainable and cost-efficient manner while addressing more formal approval processes in order to garner approval or authorization for action. Some of the realized benefits include ensuring effectiveness in the execution of reservoir management, monitor variance between actual performance and expectation during the execution of projects; and ensure production sustainability and mitigate shortfalls proactively. RPR enabled the achievement of a consistent approach across all assets for all reservoir performance review processes, while improving efficiency through automation of data gathering and presentation and the identification of all underperforming reservoir, sectors and fields.
Reservoir management excellence is achieved by delivering immediate value on the opportunities identified during performance reviews which ensure short term profitability while preserving long term goals. Typically, operators are satisfied by meeting targets within certain tolerance. RPR ensures that performance excellence is achieved by considering all technical and business aspects.
Serry, Amr (ADNOC Offshore) | Al-Hassani, Sultan (ADNOC Offshore) | Budebes, Sultan (ADNOC Offshore) | AbouJmeih, Hassan (ADNOC Offshore) | Kaouche, Salim (ADNOC Offshore) | Aki, Ahmet (Halliburton) | Vican, Kresimir (Halliburton) | Essam, Ramy (Halliburton) | Lee, Jonathan (Halliburton)
This case study demonstrates the role of nuclear magnetic resonance (NMR) T1 spectra, as used to drill complex undeveloped carbonate formations offshore Abu Dhabi. The scope of this project exceeds the traditional porosity-permeability approach to exploit the wealth of information about the rock texture, pore size distribution, flow units and a new methodology of NMR T1 data processing.
Evaluation of pore size distributions based on T1 vs. T2 spectra is addressed in two case study wells; one using a 6 ¾-in., and the other a 4 ¾-in. mandrel size for the first time in UAE. Finally, other log-derived permeabilities are presented, together with high-resolution microresistivity image interpretation and production log results in an integrated approach for improved understanding of the petrophysical character of these undeveloped units.
NMR T1 measurements are utilized for the first time in the lateral sections as part of a bottomhole assembly (BHA) consisting of a rotary steerable system (RSS), and logging-while-drilling (LWD) sensors, including high-resolution microresistivity imaging, laterolog and azimuthal electromagnetic wave resistivities, thermal neutron porosity, azimuthal density, azimuthal multipole acoustic, ultrasonic caliper and near-bit azimuthal gamma ray. During NMR T1 measurements, the spin relaxation time carries information about the liquid-solid surface relaxation and bulk-fluid relaxation, hence, it is neither affected by rock internal magnetic field gradients nor by differences in fluid diffusivity. Also, T1 logging measurements are influenced by instrument artefacts to a much lesser extent than T2 results, having several advantages over T2, especially regarding polarization and tool motion while drilling.
The real-time availability of NMR sourceless porosity measurements significantly improved drilling decisions to place the two case history wells into favourable zones and NMR T1 permeabilities were derived together with acoustic and high-resolution microresistivity image-based permeabilities which were then correlated to production logs.
The results indicate that T1 measurements are an effective, practical solution for rock quality evaluation using LWD real-time datasets free from BHA motion and fluid diffusion effects. Comparisons of T1 and T2 logs show that T1 yields equivalent formation evaluation answers, despite its sparser nature.
The T1 spectra facilitated improved pore size distribution, permeability estimation and marking of the hydraulic flow units in the heterogeneous, undeveloped Upper Jurassic reservoir units, paving the way for the consideration of T1 logging as a viable, and in some cases superior alternative to T2 logging. This paper presents the multidisciplinary approach used to benchmark and optimize the future field development program.
Unconventional and conventional reservoirs do not have much in common. They exhibit different reservoir characteristics; therefore, using conventional reservoir interpretation techniques and workflows in unconventional reservoirs could lead to incorrect conclusions.
In addition to fundamental challenges in evaluating reservoir properties, such as porosity and permeability, it is extremely important to understand reservoir fluid distribution. Downhole fluid typing and calculated volumes, together with porosity and permeability, provide more insight into reservoir potential and sweet spot zones.
Nuclear magnetic resonance (NMR) technology can be used to provide answers to some of the unknowns mentioned previously. Standard NMR measurements provide the lithology-independent porosity and permeability, and then further processing provides more details about partial porosities, volumes, and fluid types occupying the pores. Using two-dimensional maps (2D NMR) helps differentiate the reservoir fluids, especially when distinguishing hydrocarbons (HC) from water. In conventional reservoirs, it is expected to observe faster relaxation for fluid trapped in the smaller pores and longer relaxation for free fluids in the bigger pores. Industry-accepted cutoffs for T1 and T2 measurements help estimate micro, meso, and macro pores. However, for unconventional reservoirs, fluid identification using 2D maps would be different. Fluids in the small pores, such as bitumen, heavy oils, or HCs in source rock reservoir, would have a similar signature on 2D maps.
This paper presents two case studies showing how 2D NMR application was used in an unconventional reservoir for fluid typing processes and HC volumes calculation. It also shows the importance of using this method for more precise planning of further downhole activities. Core data analysis and downhole collected fluid laboratory analysis confirmed the high confidence in NMR fluid typing applications for unconventional reservoirs.
Hui, Zhou (Halliburton) | Chesnee, Davis (Halliburton) | Jay, Deville (Halliburton) | Bill, Shumway (Halliburton) | Ryan, Schiro (Halliburton) | Tim, Bailey (Halliburton) | Rob, Valenziano (Halliburton) | David, Carbajal (Halliburton)
Hydraulic modeling was used to simulate the effect of fluid rheology (both high-and low-shear-rate rheology) on the equivalent circulating density (ECD) at critical points in the well. The modeling results provided a guide for the design of nonaqueous fluid properties necessary to achieve the required ultralow ECD values. Using a combination of a rheology modifier and a new low-end fluid rheology enhancer, ultralow ECD nonaqueous fluids were successfully developed to meet the fluid rheology and barire sag requirement. The low-end fluid rheology enhancer provided a desired gel structure that helps minimize barite sag, which is often the concern for low-rheology nonaqueous fluids. The hydraulic modeling results showed that, although both high-and low-shear-rate fluid rheology must be very low to achieve ultralow ECD values, the reduction of high-shear-rate rheology has a larger effect on the reduction of ECD values. For a given ECD value, a fluid with a lower high-shear-rate rheology and higher low-shear-rate rheology is preferred because the higher low-shear-rate rheology is due to a muchdesired gel structure that helps reduce barite sag during static aging. Hole cleaning is also expected to improve with higher low-shear-rate rheology. Based on this information, a 14.0-lbm/gal clay-free nonaqueous drilling fluid was successfully formulated to achieve the required ECD without the use of micronized barite. As described, the fluid uses the combination of two rheology modifiers, one of which functions as a gel strength enhancer that provides the much-needed gel structure to minimize barite sag.
An engineered dual-purpose drilling and screen-running fluid was required to achieve optimum oil production with increased operational efficiency in a tight pressure window environment. The fluid needed to pose minimal formation damage risk while drilling and avoid completion damage through plugging of the standalone sand screen. This required a balance between bridging material content and particle size distribution (PSD), and a low fluid rheology to minimize the equivalent circulating density (ECD). The wide temperature profile and predicted restrictive narrow pressure margin in the well favored the use of a low ECD Non-Aqueous-Fluid (NAF). An organoclay-free NAF solution was selected. To reduce solids loading and ECD further, the fluid was designed with a brine phase that was high-density calcium bromide. Sized ground marble was selected to bridge the largest pore throats (42-μm) in the reservoir sand and still be screened quickly to avoid plugging of the 150-μm 6 5/8-in. standalone sand control production screens. Fluid optimization was achieved through rheology, stability, and formation-damage testing. The return permeability on cores/matched sandstone of >97%, indicated minimal formation damage risk when drilling and after production flowback/solids removal. In the field, the reservoir was drilled without major issue (i.e. no differential sticking, no down-hole losses) and the fluid quickly reached production screen test (PST) specifications prior to running screens. The sand screens were installed without issues. Although the sand section was significantly shorter than planned, the production from ~160 ft of net pay when the well was initially flowed produced as expected. After subsequent tie-in to the host floating production storage and offloading (FPSO) unit and upon choke opening, a gradual drop in production was observed. An acid job was performed via a subsea vessel-based operation and the planned production target exceeded the original clean-up well productivity.