Busaidi, Adil Zahran Al (Schlumberger) | Hawy, Ahmed El (Schlumberger) | Omara, Ahmed (Schlumberger) | Lawati, Ali Baqir Al (Schlumberger) | Vasquez Bautista, Ramiro Oswaldo (Schlumberger) | Awadalla, Muhannad (Schlumberger) | Al Ghaithi, Ghaida Abdullah Salim (Schlumberger) | Chibani, Zied (Petroleum Development Oman) | Al Jamaei, Suroor (Petroleum Development Oman)
Torsional vibration (also known as stick and slip) is a major contributor to equipment failures and severe damage when drilling the 6 1/8-in. lateral limestone Shuaiba reservoir section in PDO North Oil fields. This paper examines multiple factors that can affect the severity of stick and slip and measures their actual impact. These factors include bit/bottomhole assembly (BHA) design and formation/mud properties. The effect of a software plugin to an automated drilling system that was designed to mitigate the effects of stick and slip was also examined.
Initially, drilling dynamics data available for the lateral Shuaiba reservoir were analyzed to evaluate the levels of torsional vibration. Several proposed design changes to reduce the torsional vibration were then modeled separately using finite element analysis (FEA) to predict their dynamic behavior. Trials were conducted, and the impact of independently changing each factor in the overall torsional vibration was assessed. Data were collected from over 40 horizontal wells drilled in the same reservoir. In each set of trials, identical drilling conditions were maintained while changing a single factor.
The analyzed legacy set of well data showed high levels of torsional vibration (stick and slip) in the lateral section for different fields that share nearly the same reservoir characteristics and bit/BHA design. Using a similar formation profile, the FEA modeling results suggested that stiffening the drillstring and using heavier sets of PDC bits would greatly reduce the torsional vibrations while maintaining a good rate of penetration. When these changes were applied, actual data were analyzed to measure the improvement. Additionally, the analysis found that specific formation characteristics such as formation density highly contribute the severity of torsional vibration.
Modeling also suggested that applying higher torque to the bit reduces its RPM fluctuations and allows for lower surface parameters. This, in return, reduces the amplitude of the torsional vibration. Over eight trials were analyzed, and significant reductions in both the measured torsional vibrations levels and equipment failures and damages were seen.
Finally, the effect of utilizing a software plugin to an automated drilling system to mitigate stick and slip when drilling the 6.125-in. lateral limestone reservoir was examined. Like the other proposed solutions, the remaining factors were kept constant.
The paper offers a rare case study specific to lateral limestones reservoirs, where interbedded layers are a common contributor to the severity of torsional vibrations. The results and conclusions are based on downhole high-resolution data to calibrate finite element models to provide fit-for-purpose solutions. The results eliminate much of the theoretical explanations about root causes of torsional vibrations in limestone reservoirs.
Kumar, Kamlesh (Petroleum Development Oman) | Awang, Zaidi (Petroleum Development Oman) | Azzazi, Mohamed (Petroleum Development Oman) | Hamdi, Abdullah (Petroleum Development Oman) | Hughes, Brendan (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman)
The microporous rock types in Upper Shuaiba are low permeability ( 1mD) rocks occurring in thin (2-5 m) formations within the extensive Upper Shuaiba carbonate formations in Lekhwair. These microporous rocks constitute a significant volume of hydrocarbon in-place. Unlike the higher quality rudist-rich and grainstone rock types, appraisal pilots in the microporous areas have shown poor performance with waterflood development, which is the preferred development concept in the entire Lekhwair field. Two work streams are active in parallel to identify a technically and commercially feasible development option: Phase 1, technology trials to enable a successful waterflood implementation, and Phase 2, further studies to screen the potential of enhanced oil recovery (EOR) techniques and other light tight oil development. The technology trial work stream, initially considered four initiatives targeting injectivity improvement. To date, trials are complete for abrasive jetting and designer acid stimulation, early results are available for Directional Acid Jetting, and evaluation of Fracture Aligned Sweep Technology (FAST) is ongoing with hydraulic fracturing evaluation accelerated to Phase 1 due to synergies with the FAST evaluation.
Kumar, Kamlesh (Petroleum Development Oman) | Azzazi, Mohamed (Petroleum Development Oman) | Hamdi, Abdullah (Petroleum Development Oman) | Awang, Zaidi (Petroleum Development Oman) | Nicholls, Christopher (Petroleum Development Oman) | Lawati, Yousuf (Petroleum Development Oman) | Huseini, Hamood (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman) | Sharji, Hamed (Petroleum Development Oman)
The Upper Shuaiba reservoirs in Lekhwair consist of carbonate formations extending over a very large area (40 km × 40 km). Earlier development projects identified thicker, well-appraised formations, resulting in successful waterfloods. In contrast, challenges have been encountered in some of the waterflood pilots attempting to unlock future development areas. An integrated evaluation of these poor performing areas led to the development of a rock type catalogue that mapped out different rock types and their properties. Initial developments were mostly in high permeability rock types (Rudist Rich and Grainstone) whilst the underperforming pilots are associated with microporous rock characterized by low permeability (~1 mD) and thin formations (2-5m). These microporous rocks are associated with a large hydrocarbon volume in place. Resolving this development challenge is critical in maintaining the company's long-term production targets.
Waterflood is the preferred development concept as it is in line with the existing facilities and infrastructure. The existing pilots demonstrate that low water injectivity/throughput is the key challenge to waterflood feasibility. Conventional acid stimulation does not work in these formations. Four different initiatives, in addition to injection water quality monitoring and improvements, are being tried to ensure successful maturation of microporous resources: Abrasive Jetting: used to create small tunnels up to 3m into the reservoir. Controlled Directional Acid Jetting: using acid to create multiple small laterals (up to 12 m in length) into the reservoir. Designer Acid: acid tailored to improve conventional acid stimulation. Fracture Aligned Sweep Technology (FAST) as implemented in Halfdan field; which creates longitudinal fractures along the length of the well.
Abrasive Jetting: used to create small tunnels up to 3m into the reservoir.
Controlled Directional Acid Jetting: using acid to create multiple small laterals (up to 12 m in length) into the reservoir.
Designer Acid: acid tailored to improve conventional acid stimulation.
Fracture Aligned Sweep Technology (FAST) as implemented in Halfdan field; which creates longitudinal fractures along the length of the well.
The outcome of this study includes identification and mapping of the different rocktypes across the entire Upper Shuaiba; waterflood performance assessment of microporous rocks and new technology trials to accelerate the development of microporous resources. Whilst abrasive jetting has achieved limited success in improving injectivity, result from designer acid stimulation was disappointing. The other two trials are still under evaluation. In case all the initiatives fail to establish the feasibility of waterflood, alternate developments mechanisms are proposed as Phase 2 in the strategy.
This paper highlights how integration between different disciplines can help in maturation of a large resource volume, whilst accelerating its development by standardization of designs.
El Hawy, Ahmed (Schlumberger) | Al Busaidi, Adil (Schlumberger) | Vasquez Bautista, Ramiro Oswaldo (Schlumberger) | Awadallah, Muhannad (Schlumberger) | R. Heidari, Mohammad (Schlumberger) | Saidi, Khaled (Schlumberger) | Escamilla, Barton (Schlumberger) | Al Abri, Zahran (Petroleum Development Oman) | deBoehmler, Guy (Petroleum Development Oman) | Al Harthi, Said (Petroleum Development Oman) | Haeser, Patrick (Petroleum Development Oman) | Al Riyami, Khaleel (Petroleum Development Oman) | Picha, Mahesh (Petroleum Development Oman)
As one of the worst oil & gas business downturns struck, the need for a revolutionary approach of drilling was needed. Optimization was the key word during that period, it was about time to look back at drilling fundamentals, review and learn from previous failures and lessons while establishing new foundation for a transformed yet successful process that ensured an all-time historical success.
While many trials of drilling optimization initiatives were executed over the years, inconsistent drilling performance delivery and repetitive failures continued to raise a red flag each time for variety of reasons.
From challenges achieving required performance levels and dog legs in the top sections with increased risks of axial and lateral vibrations, to the difficulties faced in the landing section drilling through unconsolidated and reactive shales in the north, and through fragile weak formations in the south to the difficulties transferring weight to the bit at deeper depths in the horizontal laterals drilling highly porous zones of sticky limestones.
While cost optimization was the trend during the downturn, there was no better option to achieve desired financial results for both operator and service provider than the inclusion of the drilling optimization in action initiative into every well drilling program, it was proven to be an ultimate win-win technical and business solution.
Huang, Qingfeng (Abu Dhabi Marine Operating Company) | Arii, Hiroaki (Abu Dhabi Marine Operating Company) | Sadok, Abdel Aziz Ben (Abu Dhabi Marine Operating Company) | Baslaib, Mohamed A. (Abu Dhabi Marine Operating Company) | Sasaki, Akihito (Abu Dhabi Marine Operating Company)
Infill drilling has been recognized as a common practice to accelerate oil production and increase ultimate recovery. Infill drilling can be performed under different drive mechanisms (primary, secondary and tertiary). With a certain history of development, many oil fields have become mature to some extend with waterflood. In order to have a sustainable corporate development plan, pattern flood towards further EOR is considered. Nonetheless a tertiary process as a whole project involves massive investment with high risks and uncertainties. If incremental oil can be recovered via infill drilling as a transition, the investment can be partially offset and justified. Infill oil producers as components of pattern flooding can be accelerated while pattern water injectors can be scheduled in a latter phase.
Two main approaches are used in the determination of infill potential. The first one uses empirical techniques to determine infill wells number and spacing based on volumetric calculation of oil in place. It ignores impact of reservoir heterogeneity and continuity. The second approach relies on numerical simulation coupled with optimization algorithms. Based on the second approach, this paper presents a new one that looks at the remaining mobile oil distribution at the time of infill drilling, and locates the optimum pattern configurations whose centers have the maximum sum of stacked mobile oil thickness of each pattern. Each square pattern has only one oil producer centered without corner water injectors.
An automated algorithm has been generated to identify infill potential and locations. First, the remaining stacked mobile oil distribution is calculated; second, multiple average-spacing pattern realizations are placed on the field, and only one realization is chosen since it has the highest value of summing mobile stacked oil thickness; third, remove infill wells which have nearby existing oil producers in the pattern area; then, select perforation intervals with a certain criteria to avoid early water/gas breakthrough; after that, an automatic schedule of infill wells is output for simulation run to screen potential infill wells having minimum impact on the existing wells.
This infill drilling approach identifies potential pattern oil producers to recover mobile oil, sustain the production plateau and increase oil recovery, prior to planning pattern water injectors. In offshore field, tower slots are limited, so some infill wells can be utilized to workover/sidetrack future inactive wells to save slots. Infill wells can be coupled utilizing conventional completion strategy to minimize wells count. These wells act as a smooth transition to future pattern configurations towards further EOR to recover remaining oil.
For the first time, this paper demonstrates a novel approach of determining infill locations by chasing in-situ stacked mobile oil thickness at the specified time step. An automated program is generated to efficiently identify infill wells at any time step. A complete workflow of infill drilling and transition to pattern flood is prepared for a full image. This process also suits both new and mature field. Pattern flood is accelerated by drilling infill oil producers and followed by water injectors.
Al-Hashemi, Hussain Hamood (ADCO - Abu Dhabi Co for Onshore Oil Operation) | Masoud, Rashad Mohamed (Abu Dhabi Co For Onshore Oil Operation) | Al Ammari, Khalid Ali (Abu Dhabi Co For Onshore Oil Operation) | Mohamed, Mohamed Elgohary (ADCO Producing Co. Inc.) | Moen-maurel, Laure (Total)
Carbonate Reservoirs are well known for their heterogeneity in terms of porosity and permeability. In this field case from UAE onshore a sharp degradation of petrophysical quality was noted at the gas-water contact, in relation to diagenetic cementation, and led to an independent modelling for the aquifer, as well as an independent modelling of the reservoir with a data filter for the gas pool only. A merge of the 2 grids was then performed.
In this field a major bias on well data distribution from crest to aquifer affects the geostatistical histogram evaluation: wells are concentrated in the crest down to mid-flanks while there are few wells from mid-flanks to the aquifer. Consequently distribution histograms of petrophysical data from the whole model should not respect well data histograms (whether, core-, log- or cell-derived).
The methodology of separating gas and aquifer modelling, and of separating well derived histograms from model-derived ones led to the following results:
- Better capture of the reservoir degradation with depth in the gas pool,
- Better capture of the sharp degradation break in the aquifer.
This paper is focusing on the methodology of how to build two separate models in the gas pool and the aquifer for each petrophysical property and how to combine them in one property model to honour reservoir heterogeneity.
Integration of all data at all scales and constant QC between database sources (logs, cores, seismic, dynamic history) were the means to produce a geomodel capturing the key heterogeneities of the reservoir, those with major impact on fluid front migration during production.
De Berredo, Marcos (Petroleum Development Oman LLC) | Sipra, Iqbal (Petroleum Development Oman LLC) | Al Muqbali, Harith (Petroleum Development Oman) | Al-Bimani, Atika (Petrolum Development Oman LLC) | Lanier, G. H. (Petroleum Development Oman)
Petroleum Development Oman LLC (PDO) production activities rely significantly upon artificial-lift technology due to the nature of the reservoir fluids and properties. Currently, about 90% of the wells require some method of artificial-lift in PDO. Many existing and future wells will eventually produce with more challenging or high GOR conditions which results in technical and economic challenges to select the appropriate artificial-lift method, as well as, the well completion configuration.
Conventional ESP applications are ideal for high production rate wells with moderate gas rates. Gas lift applications often target medium to low production rate wells and can easily tolerate high gas volumes. Within PDO, gas lift conversions to ESP are growing more common due to reasons related to facilities constraints (e.g. gas compression / injection gas volume, aging compressors, gas flow-lines integrity, etc), declining reservoir pressures due to ineffective water injection or increasing water cut. As a result, some new ESP wells are now producing at higher GOR.
For field developments, artificial-lift concept selection is often one of the key decisions to be assured at the concept selection milestone. In marginally-economic fields, the choice of artificial-lift method can easily erode the project value, especially owed to significant uncertainties with regards to potentially high producing GOR risks. In fact, this was demonstrated during the development planning process for a high GOR field which is generically referenced in this paper as field T in North of Oman with an initial solution GOR of 216 Sm3/m3. In this particular case, artificial-lift selection was based not only on economical terms but also on technical and operational feasibility aspects.
Based on current PDO`s experience to date operating high GOR wells, the ESP method was identified during the study as the preferred artificial-lift method for field T. An ESP feasibility evaluation was completed and included a detailed assessment of the expected range of free gas at the well pump intake depth for the entire field production life-cycle. This evaluation considered the completion configuration, as well as, gas-handling and separation equipment limitations. By adjusting the well and reservoir field management plan for field T and incorporating the latest PDO experience and learning's to date, the study provided the technical basis to assure feasibility of the proposed development plan for the expected high GOR producing environment. Further economic assessment of the artificial-lift selection decision, which is not detailed in this paper, supported a significant impact to the project on the order of 1/3 of its expected value.
This paper summarizes the range of PDO operating experience to date with ESPs installed in high GOR conditions. Additional details are shared regarding the feasibility study for field T including supporting rational for the artificial-lift selection for the project concept selection, proposed well completion concept design and the artificial-lift economic evaluation. Finally, established best practices for high GOR fields and key challenges going forward will be discussed.
An important aspect of oil field management is to compare a field's recovery performance with analogues to assess whether the field is being fully exploited and economic recovery is being maximized. However, this can be difficult when there are many differences in basic parameters that might impact recovery potential. A number of qualitative methods have previously been developed but they tend to be too generic to allow meaningful recovery potential analysis.
The objective of this study has been to develop a tool to assess and understand the recovery performance of offshore Danish fields in relation to world analogues. This can be done meaningfully in a semi-quantitative fashion by limiting the analysis to chalks and by calibrating, where practical, the impact of key parameters with reservoir simulation analysis. The main steps in the study were to establish the principal geological and dynamic drivers determining recovery factors in chalks; build a "calibrated?? recovery factor potential model and apply it to worldwide chalk fields, using published data.
The results show that the Danish chalk fields become progressively more complex going from the Tor formations, which have been successfully waterflooded; to the Ekofisk, where there remains technical potential for implementing waterflooding; to the Lower Cretaceous where waterflooding recoveries are theoretically comparable to depletion but due to complexity and expense are unlikely to be attractive. A number of reservoir management activities have been identified to increase recoveries. Overall the Danish field recoveries compare favourably with world analogues. Operators in the Danish sector are likely leaders in exploiting more complex and particularly lower permeability chalk fields.
The Recovery Factor Potential tool developed in this study allows chalk field performance to be compared in a more quantitative manner, making it easier to understand causes of underperformance and to identify reservoir management activities to increase recovery.
An important aspect of oil field management is to compare a field's recovery performance with analogues to assess whether the field is being fully exploited and economic recovery is being maximized. However, this can be difficult when there are many differences in basic parameters that might impact recovery potential. To tackle this problem a study has been conducted jointly by Maersk Oil and Foroil aimed at developing correlations that enable comparisons of oil recovery performance of chalk fields around the world.
A number of approaches have been taken in the industry to develop general correlations that can assess a field's recovery against its "complexity index". The complexity index has generally been based on combining a number of key factors (such as structural complexity, reservoir heterogeneity, STOIIP concentration, permeability etc.). Typically each factor has a range of choices (say 1 to 5) of increasing complexity and each factor is given an appropriate weighting. Such tools are useful in giving a qualitative impression of whether the field is being well managed and can highlight the factors that make a field complex so that these complexities can be managed.
This study has focused on chalk reservoirs and as a consequence it has been possible to create a more quantitative model using reservoir modelling and considering chalk-specific factors, such as reservoir compaction, to assess the impact of a number of the important factors. As a consequence the tool has been constituted as a "Recovery Factor Potential" (RFP) tool.
In addition, having established the RFP there has been a focus on investigating the deficit between the actual field projected recovery and its RFP to assess whether any remedial activity can be taken. This has been done for both world chalk analogues and the DUC (Dansk Undergrunds Consortium) Danish fields.
Bashatah, Lafya (Abu Dhabi Marine Operating Co.) | Al-feky, Mohamed Helmy (Abu Dhabi Marine Operating Co.) | Draoui, Elyes (Abu Dhabi Marine Operating Co.) | Ghalem, Salim (Abu Dhabi Marine Operating Co.) | Alurkar, Kaustubh D. (PetroTel Inc) | Graves, Hunter (Petro Tel, Inc.) | Jayanti, Shekhar (PetroTel Inc) | Giordano, Ronald M. (PetroTel Inc) | Farouk, Magdy (Abu Dhabi Marine Operating Co.)
Streamline analysis coupled with finite-difference simulation provides a novel effective approach for an integrated reservoir management. The output from the existing compositional reservoir model was processed to generate streamlines from the finite-difference simulation. Reservoir management data, historical well performance data, calculations from streamline bundles, and novel performance diagnostics are integrated to optimize the field management and maximize oil recovery.
Simulation and field data are combined to give an integrated understanding of the reservoir leading to smart reservoir management. Powerful streamline analysis is being used to help optimize injection and increase recovery efficiency. Real field data and model data are being analyzed to identify the areas of upswept oil and opportunities to improve the reservoir performance. This new methodology workflow is implemented in a user-friendly and intuitive way, giving more time for analysis and integration then data management.
This new integration methodology is applied for the first in UAE to integrate Reservoir management data, historical well performance data, calculations from streamline bundles, and novel performance diagnostics. It is a unique well, reservoir and field management application that can assist to optimize field development and maximize hydrocarbon resource value. This new methodology is designed to visualize flow paths, compute allocation factors, assess pattern performance, and optimize injection based on injector-producer connections. It can be used to generate and analyze streamlines, quantify fluxes, and visualize the performance of a reservoir. It can help in identifying un-swept regions of oil, dead spots, and low pressure regions. An analysis of the historical data was conducted to understand the development history. Diagnostic analysis techniques were used to evaluate the water and gas flood and identify problems and opportunities. This work was accomplished in three phases:
1- First phase: incorporation of reservoir management data into the "Analytics project", this part of the study allows field, zones and sector performance analysis after loading of the following data:
A project study has been performed in order to evaluate a number of reservoir characterization and petrophysical parameters using Digital Rock Physics (DRP) technology in complex carbonate reservoir, on-shore Abu Dhabi. High-resolution images (X-ray micro-tomographic) of the rock's pores and mineral grains were obtained, processed and the rock properties were evaluated by numerical simulation of the physical processes of interest at the pore scale.
The selection of core samples in carbonate reservoir was performed with considering reservoir rock type, logs and routine core analysis data for validation and application phase. A set of special core analysis (SCAL) data were acquired earlier on the core samples in different carbonate reservoir rock types of varying levels of heterogeneity, lithology, porosity, and absolute permeability. This set of measurements formed the baseline for our validation study, then similar DRP approach and improvement is applied for non-SCAL cores. This process is used in DRP study to evaluate cementation exponents ‘m', saturation exponents ‘n', water-oil relative permeabilities, capillary pressures and elastic parameters such as compressional/shear wave velocities.
An integration of core and logs data in particular carbonate reservoir has been used to provide accurate and reliable results in the validation phase of DRP. It has been observed in DRP that connected micrite phase conductivity contribution has been determined for improvement approach by assigning a finite conductivity smic to the micrite phase to get reliable formation factor, cementation and saturation exponent. DRP and core J-capillary were integrated to provide reliable saturation-heights in this carbonate reservoir. The integration of formation evaluation in this case study has provided improvement, reliability in DRP results for formation evaluation and the potential to improve the quality and timeliness of carbonate reservoir characterization.