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.
The latest developments in well construction rely on advanced drilling and completion technologies to withstand increased wellbore deviation, tortuosity, and complex geometry challenges necessary to access reservoirs, which can create challenges to cement placement between reservoir zones. Hence, well integrity and reservoir management concerns can arise given the possibility for multiple reservoirs to communicate, resulting in undesired crossflow and water production because of poor cement isolation. Poor cement placement behind casings, ineffective zonal isolation, and well integrity issues have been traditionally addressed using workover or drilling rigs to remove production tubing and perform either a remedial cement squeeze or zonal abandonment for subsequent sidetrack. However, this generally entails production deferral, capital-intensive rig rates, the potential risks of pulling and running production tubing, which often translates in formation damage from killing the well, large wellsite footprint requirements, and higher logistic demands for rig support equipment. This paper describes the systematic process used to identify, diagnose, design, and execute a successful inter-reservoir crossflow mitigation operation in a naturally fractured carbonate formation in Abu Dhabi using a cost-effective solution with rigless coiled tubing-deployed technologies and a hydrocarbon-based microfine cement slurry that activates upon contact with water. The results enabled the operator to restore reservoir integrity, improve reservoir management, and enhance water sweep. Post-operation reservoir evaluation validated the successful use of the technology for rigless zonal isolation using coiled tubing (CT) for the first time in the United Arab Emirates, providing significant cost benefits and new best practices to reduce the water cut and restore wellbore integrity.
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.
Managing sustainable annulus pressure (SAP) is critical for maintaining well integrity since it poses significant health, safety and environmental (HSE) risks. For safe operation of the aging wells (40+ years old) beyond their design life, it is critical to accurately define maximum allowable annulus surface pressure (MAASP) limits, and manage SAP below MAASP to avoid casing burst, collapse and leak scenarios.
This paper reviews different industry standards, and recommends derating factors guidelines to account for corrosion in aging wells for MAASP and maximum allowable wellhead operating pressure (MAWOP) calculations. Corrosion rates are calculated by analyzing inspection data obtained using multi-finger caliper, ultrasonic and electromagnetic tools on various tubulars over their operational life. Corrosion rates are further used to define casing collapse and burst derating factors as a function of well age, cement conditions, annulus fluid and any known well integrity issues. Well specific annulus pressure limits have been developed and successfully implemented in the field to safely operate wells with annulus pressure.
Various industry standards such as API RP90, ISO 16530-2 and NORSOK D10 provide guidelines on MAASP calculations for annuli, but they differ in implementation of the derating of tubulars in aging wells due to corrosion/wear. Furthermore, most of these derating factors are independent of well age, annuli fluid and cement conditions, and typically require operators to use casing inspection data to define MAASP and MAWOP limits. Learnings from historical casing inspection and well operating environments are captured in the form of best practices and implemented in the form of an Excel model. Effects of cement conditions and annuli fluid on external corrosion of casing are also evaluated. Annuli fluid samples were collected and analyzed in the lab to measure corrosiveness, and further refine derating factors. This work enables a systematic approach to: Assess current integrity of wells Reduce HSE risks in wells with SAP by reducing injection pressure Establish systematic well integrity monitoring and mitigation plans Define remaining life of tubulars from a corrosion perspective Effectively plan the workover activities and minimize impact on production/injection rate Conduct safe operations with reduced well failure incident probability including Crude/ gas leakage Well collapse or burst probability Formation fracture by proactive well monitoring
Assess current integrity of wells
Reduce HSE risks in wells with SAP by reducing injection pressure
Establish systematic well integrity monitoring and mitigation plans
Define remaining life of tubulars from a corrosion perspective
Effectively plan the workover activities and minimize impact on production/injection rate
Conduct safe operations with reduced well failure incident probability including Crude/ gas leakage Well collapse or burst probability Formation fracture by proactive well monitoring
Crude/ gas leakage
Well collapse or burst probability
Formation fracture by proactive well monitoring
Brindle, Frank (ADNOC Offshore) | Rafique, Maqsood (ADNOC Offshore) | Thatha, Rajesh (Petromac Limited) | McCormick, Stephen (Petromac Limited) | Escott, Samuel (Petromac Limited) | Bajwa, Haroon (Schlumberger) | Cocagne, Michael (Schlumberger)
Drill Pipe conveyance (TLC/PCL) of wireline logging tools or Logging While Drilling (LWD) is usually required for high deviation / high differential sticking risk logging scenarios. These are costly in terms of rig time and service company costs. This paper details how a full suite of high-quality open hole log data was obtained on wireline in a high angle 16,500ft wellbore utilizing a new conveyance system and a polymer-locked high strength cable.
The new conveyance system, utilizing wheeled carriages and a holefinder with nose angled upwards, takes a holistic approach to tool conveyance, reducing drag while ensuring both correct tool orientation and optimum contact and standoff for each logging service. Management of tool centers of gravity relative to the wheel axes ensures correct orientation. The reduction in friction due to wheeled carriages vs weight and cable load is modelled before the operation in order to ensure successful runs, both into and out of the wellbore. Polymer-locked high strength cable significantly increases maximum safe pull capability and enhanced data transmission technology allows faster logging speeds, greater rig time efficiency and reduced sticking risk.
The wheeled carriage system enabled conventional logging in a high angle well, minimized stick-slip and reduced differential sticking risk. The unique holefinder prevented tool hold up during descent. The Vertical Seismic Profile (VSP) run (the only run not able to utilize the system due to tool size and design) was held up on a ledge above the lowest reservoir of interest. The high strength cable allowed safe retrieval of tools (over-pull > 6000lbs) in one particularly sticky zone.
In a world first, an array sonic tool was centralized through management of weighted and eccentralized tool sections using bespoke wheels. This eliminated the drag inherent to traditional methods of sonic centralization (centralization using powered calipers and/or spring centralizers), resulting in excellent data quality. Nuclear Magnetic Resonance logs were obtained by orienting the tool sensor with wheels which utilized tool weight to provide sensor application force. This removed the need for additional centralizers, resulting in data devoid of stick-slip artefacts (an issue in previous wells).
The formation fluid sampling run was conveyed on drill pipe, taking 6 days of rig time. There are further significant efficiency gains to be had on future operations by using the new conveyance system on sampling tools (operators have already moved in this direction in the Gulf of Mexico).
Javid, Khalid (ADNOC Offshore) | Mustafa, Hammad (ADNOC Offshore) | Chitre, Sunil (ADNOC Offshore) | Anurag, Atul (ADNOC Offshore) | Sayed, Mohamed (ADNOC Offshore) | Kuliyev, Myrat (ADNOC Offshore) | Mishra, Anoop (ADNOC Offshore) | Al Hosany, Khalil (ADNOC Offshore) | Saeed, Yawar (Schlumberger)
The workflow is implemented for designing Lower completion with inflow control devices &/or inflow control valves (ICD/ICV) for high departure long horizontal wells in a Green Field located North West offshore Abu Dhabi. The major challenges that being faced in the field development include reservoir heterogeneity with high permeability contrast ranging from 0.1 to 500 md, fault network and high uncertainty about Tar Mat surface & Oil Water contact. Main objectives of ICD/ICV completions are; to have uniform influx/flow profile from all sublayers of reservoir by dividing horizontal drain in compartments based on reservoir properties variations, minimize heel to Toe effect, controlled inflow from high permeability streaks, without compromising total well deliverability; most importantly to encourage more inflow from the lower permeability regions. An appropriate reservoir sector model having one deviated gas injector, one/two horizontal water injector(s) and one ICD/ ICV candidate oil producer was extracted to be used for this study. Single time step static modelling and dynamic sector modeling simulation approaches were implemented for ICD/ICV modeling.
BinAbadat, Ebtesam (ADNOC Offshore) | Bu-Hindi, Hani (ADNOC Offshore) | Lehmann, Christoph (ADNOC Offshore) | Kumar, Atul (ADNOC Offshore) | AL-Harbi, Haifa (ADNOC Offshore) | AL-Ali, Ahmed (ADNOC Offshore) | Al Katheeri, Adel (ADNOC Offshore)
In this study, core and log data were integrated to identify intervals which are rich in stromatoporoids in an Upper Jurassic carbonate reservoir of an offshore green field Abu Dhabi. The main objective of this study was to recognize and stromatoporoids floatstones/rudstones in core, and develop criteria and workflow to identify them in uncored wells using borehole images.
The following workflow was used during this study: i) Identification of the stromatoporoid feature in pilot wells with core and borehole images, ii) Investigate the properties and architecture of stromatoporoid bodies, iii) Integrate the same scale of core observations with borehole images and conventional log data (gamma ray, neutron porosity and bulk density logs) to identify stromatoporoid-rich layers, iv) Performing a blind test on a well by using the criteria developed from previous steps to identify "stromatoporoid accumulations" on a borehole image, and validate it with core observations.
In the reservoir under investgation, stromatoporoid floatstones/rudstones intervals were identified and recognized both on core and borehole image in the pilot wells. These distinct reservoir bodies of stromatoporoids commonly occur in upper part of the reservoir and can reach to a thickness of around 20ft. The distribution and thickness of stromatoporoid bodies as well as growth forms (massive versus branching) were recognized on core and borehole images. The accumulations varied between massive beds of containing large pieces of stromatoporoids and grainstone beds rich in stromatoporoid debris. The massive beds of stromatoporoid accumulations are well developed in the northern part of the field. These layers can enhance the reservoir quality because of their distinct vuggy porosity and permeability that can reach up to several hundred of milidarcies (mD). Therefore, it is important to capture stromatoporoid layers both vertically and laterally in the static and dynamic model. Integrating borehole image data with core data and developing a workflow to identify stromatoporoid intervals in uncored wells is crucial to our subsurface understanding and will help to understand reservoir performance.
Integration of image log data which is calibrated to core and log data proved to be critical in generating reservoir facies maps and correlations, which were integrated into a sequence stratigraphic framework as well. The results were used in the static model in distribution of high permeability layers related to the distribution of stromatoporoids.
Franquet, Javier (Baker Hughes, a GE company) | Shaver, Michael (ADNOC Offshore) | Edwards, Ewart (ADNOC Offshore) | Neyadi, Abdulla Al (ADNOC Offshore) | Noufal, Abdelwahab (ADNOC Upstream) | Khairy, Hamad (Baker Hughes, a GE company)
A pilot was drilled offshore Abu Dhabi aiming to determine the in-situ stress magnitudes. A time-dependent reactive shale formation separates Middle and Lower Cretaceous Limestone formations, leading to difficult open-hole logging conditions. Determining the stress regime and stress contrast across these formations is critical for assessing wellbore stability in extended-reach wells, setting casing shoe depths, and designing hydraulic fracturing in the tight reservoirs. Therefore, a comprehensive logging including multiple in-situ stress measurements and full-core was acquired.
Seven microfrac stress measurements were obtained in one pipe-conveyed straddle-packer run conducted in a 15°-degree deviated 8½-in. open-hole wellbore. Each microfrac test was designed with multiple pressurization cycles to accurately obtain the closure stress away from the near-wellbore zone. Core and logging data from offset wells were used to calibrate the pre-job microfrac assessment. Real-time data monitoring was implemented for quality-control and tool operation decisions while logging. Three different pressure-decline analysis methods were used to identify the fracture closure: (i) SQRT square-root of time, (ii) G-function, and (iii) Log-Log plot on each microfrac station.
The pilot well required an inhibited oil-based mud system to stabilize the 360-ft. water-sensitive shale formation. All microfrac stress measurements successfully reached the formation breakdown pressure, providing clear propagation and fracture closure identification. The three pressure decline methods produced results around ± 15 psi from each other with G-function predominately higher and Log-Log predominately lower than the SQRT. These microfrac tests measured minimum horizontal stress gradients between 0.67 to 0.77 psi/ft confirming the normal faulting stress regime in the studied reservoirs and a near strike-slip stress regime in the intervening shale formations. The formation breakdown, fracture reopening and closure pressure provide an accurate present-day tectonic model with ~0.1 and ~0.9 mStrain in the minimum (N80°W) and maximum (N10°E) horizontal stress directions in the absence of breakouts and induced fractures on image logs. The Lower Cretaceous tight reservoirs, identified as generally thin (<10-30ft) and low-quality (<10mD, locally <1mD) microporous carbonates, were located between low stress contrast (0.69 psi/ft) clay-rich limestones intervals in the overburden and high stress contrast (0.74 psi/ft) denser dolomites and clean tight limestones in the underburden.
The risk of tool plugging and unsuccessful latching due to large particle solids in the mud was mitigated by multiple mud filters and repeated circulations while running-in hole with the straddle packer module. The microfrac tests in the Lower Cretaceous tight reservoirs provide the stress contrast measurements to properly evaluate hydraulic fracture containment on these tight reservoirs for future field development plans.
Bermudez Alvarado, Romulo (ADNOC Offshore) | Navas, Luis (ADNOC Offshore) | Mahamat Habib, Abdelkerim Doutoum (ADNOC Offshore) | Al Katheeri, Yousif (ADNOC Offshore) | Krieger, Sebastian (Weatherford) | Kiess, Christian (Weatherford) | Farley, Douglas (Weatherford) | Mostafa, Khamis (Weatherford) | Shaker, Sherif (Weatherford) | Khallaf, Ahmed (Weatherford) | Rajadhyaksha, Sachin (K&M Technology Group)
This paper describes how the unique centralizer requirements for extended reach drilling (ERD) wells can be attained. By continuously evaluating past casing runs in combination with engineering input, the learning curve led from a standard centralizer to a highly customized solution. The necessary flow path target to enhance the wellbore isolation through cement placement is met by achieving the right centralizer performance and placing.
A single-piece high-restoring-force centralizer is the best solution for the high inclination well profile to obtain the required 9 5/8-in. casing stand-off for ERD wells.
The original centralizer design experienced challenges such as high doglegs in some of the longest 9 5/8-in. casing strings that have been run in the UAE to date. Customize the centralizers for different well profiles was necessary. They were developed and tested according to the latest
Initially, a standard off-the-shelf design of a 9 5/8-in. x 12 1/4-in. single-piece centralizer was used in two wells with the following results: Friction factor exceeded the expected values across the interval on occasion. Total Depth (TD) was sucessfully reached by washing down to bottom. Good centralization as per software design was attained (tageting 80%) with moderate to good isolation.
Friction factor exceeded the expected values across the interval on occasion.
Total Depth (TD) was sucessfully reached by washing down to bottom.
Good centralization as per software design was attained (tageting 80%) with moderate to good isolation.
Due to the performance, while running in the hole (RIH), concerns arose due to the unexpectedly high friction factor which, could lead to difficulties RIH and reaching TD in future wells. The modified centralizer design has led to the following improvements: Reduction of friction factor to an average of 0.24 due to a significant decrease in the centralizer running force even through reduced hole diameter intervals and the high dogleg severities (DLS) Reaching TD successfully. Stand-off remained around 80%, as demonstrated by outstanding cement bond log results across the critical sections.
Reduction of friction factor to an average of 0.24 due to a significant decrease in the centralizer running force even through reduced hole diameter intervals and the high dogleg severities (DLS)
Reaching TD successfully.
Stand-off remained around 80%, as demonstrated by outstanding cement bond log results across the critical sections.
It is important to consider that this centralizer was designed not to lose any performance after being run through reduced hole diameter intervals. The application of enhanced centralization design (i.e., standoff >80%) ensured good quality of the cement job.
Kumar, Amit (ADNOC Offshore) | Srivastava, Manish (ADNOC Offshore) | Al Shehhi, Ali (ADNOC Offshore) | Al Daghar, Tariq (ADNOC Offshore) | Abdulhai, Walid (ADNOC Offshore) | Gan, Chee-Lam (ADNOC Offshore)
Most of the existing wells in a giant oil offshore field in Abu Dhabi are equipped with L80-13Cr corrosion resistant alloy (CRA) tubulars to provide protection from CO2 corrosion due to sweet nature of reservoir. Recently, some of the wells are showing a presence of mild H2S due to unexpected reservoir souring or other geological changes. The presence of H2S in production fluids raises concerns about sulfide-stress-cracking (SSC) of L80-13Cr. As L80-13Cr CRA has been known to have limited SSC resistance, it is important to understand the maximum acceptable limit of H2S in production fluids for safe operation.
Industry standards such as ISO15156/ NACE MR0175 and NORSOK-M-001 recommend safe acceptable limits of H2S for 13Cr tubular materials based on the partial pressure of H2S. However, these approaches do not take into account the effect of temperature, or non-ideal gas behavior of H2S at high pressure. Pressure, temperature, salinity and pH in the wellbore impact the solubility and chemical behavior of H2S in the water phase which defines the corrosive environment to which the material is exposed. Therefore, it is important to include non-ideal gas and solution behaviors in order to define the acceptable limit of H2S for fitness-for-service (FFS) material evaluations.
In this work the acceptable limit of H2S in the wellbore was determined using a combination of thermodynamic modeling and field corrosion data. A molecular thermodynamics approach was used to calculate pH and dissolved H2S levels in water along the production tubing length. Shut-in and production operation scenarios were simulated to identify the worst-case scenario using thermal modeling software. Furthermore, tubing inspections were conducted using a multi-finger caliper tool to identify any corrosion damage. All of this information was used to identify the acceptable limit for H2S in the wellbore. This approach to determining acceptable H2S limits will avoid unnecessary workovers and enables cost saving through continued use of existing materials. Furthermore, it supports the development of a corrosion monitoring plan, and FFS assessment of tubulars based on the wellbore environment.