Carlsen, Mathias (Whitson) | Whitson, Curtis (Whitson) | Dahouk, Mohamad Majzoub (Whitson) | Younus, Bilal (Whitson) | Yusra, Ilina (Whitson) | Kerr, Erich (EP Energy) | Nohavitza, Jack (EP Energy) | Thuesen, Matthew (EP Energy) | Drozd, John (EP Energy) | Ambrose, Ray (EP Energy) | Mydland, Stian (NTNU)
The objective of this paper is to help understand the mechanisms behind gas-based enhanced oil recovery (EOR) seen in actual field performance. This is accomplished by computing and interpreting daily wellstream compositions obtained from production data during the production period(s) of Huff-n-Puff (HnP) wells in the Eagle Ford, together with relevant PVT and numerical modeling studies.
Wellstream compositions are determined from readily available production data using an equation of state (EOS) model and measured oil and gas properties obtained from sampling at the wellhead. The wellstream composition is estimated daily in one of the following two ways: (1) if measured properties from field sampling are available, then regress to find a wellstream composition that matches all the measured oil and gas properties (e.g. stock-tank oil API, gas specific gravity, GOR, and separator fluid compositions). (2) if no measured properties from field sampling are available, then flash the most-recent wellstream composition estimated from (1) and recombine the resulting oil and gas streams to match the producing GOR.
Multiple lab-scale HnP EOR experiments and associated results have been published earlier, but only limited amounts of compositional data have been presented. In this study, we attempt to link produced wellstream compositions with simulated laboratory compositions reflecting different EOR recovery mechanisms. These results should enhance the understanding of the HnP EOR mechanisms to further optimize injection and production strategies, ultimately leading to higher recoveries. The data and observations from this analysis are presented in detail. The wellstream compositions before and after HnP implementation are shown and interpreted.
By providing daily estimates of oil and gas compositions, the compositional tracking technology presented in this paper can be used as a tool to understand key mechanisms behind the reported uplift seen in EOR in unconventional resources. The identification of these mechanisms is important for companies that are implementing EOR, because it allows them to optimize their EOR strategies, target higher recoveries, and increase the technical certainty in reserve booking.
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.
Capillary pressure is a crucial step in reservoir properties definition and distribution during static and dynamic modelling. It is a key input into saturation height modelling (SHM) process, understanding the fluid distribution and into reservoir rock typing process. Capillary pressure models provide an insight into field dynamic for the identification of swept zones and provide another calibration besides the log calculated saturation. Capillary pressure curve tends to be more complex in carbonates in comparison to sandstone reservoirs because of post deposition processes that impact the rock flow properties, hence complex pore throat size distribution (uni-modal, bi-modal or tri-modal). Therefore, accurate determination of this property is the cornerstone in the reservoir characterization process.
Capillary pressure can be obtained using several experimental techniques, such as mercury injection (MICP), centrifuge (CF) and porous plate (PP). Each method has its own inherited advantages and disadvantages. The MICP method tends to be faster, cheaper and provides a full spectrum of pore throat size of a plug. Whereas, the PP method can be carried out at reservoir conditions with minimum required corrections.
In this paper, a detailed workflow for quality control capillary pressure is discussed. The workflow is sub-divided into three main parts: Instrumental and experimental level, core measurement level and logs level. Experimental level starts with proper designing the actual procedure of the capillary pressure experiment. Parameters such as pore volume, bulk volume and grain density are investigated at core measurement level. In geological-petrography montage, all petrography data; X-Ray Diffraction (XRD), Scanning Electron Microscope (SEM), thin section and computed tomography scan (CT) are used along with the capillary pressure curve for assessment. Comparing various methodologies of experimental technique carried out on twin plugs, if exist, are also investigated. The capillary pressure that passes the previous QC steps is used as input into saturation-point comparison as a logs level QC. The saturation calculated from capillary pressure is compared to log-derived water saturation eliminating any issues with porosity and permeability of the trims and provides insight to the uncertainty level in the model. As an additional step, the MICP measurements are fitted with bi-modal Gaussian basis functions with two practical benefits. First, the quality of this fitting is a useful indicator for the evaluation of pore structure complexity and the identification erroneous measurements. Second, the fitting parameters are useful inputs for geological interpretation, rock typing and SHM. This rapid and automated workflow is a useful tool for screening, processing and integration of large-scale capillary pressure data sets, a key step in integrated reservoir description, characterization and modelling.
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.
Flow zonation and permeability estimation is a common problem in reservoir characterization; usually, integration of openhole log data with conventional and special core analysis solves the latter. We present a Bayesian based method for identifying hydraulic flow units in uncored wells using the theory of Hydraulic Flow Units (HFU) and subsequently compute permeability using wireline log data.
First, we use the F-test and the Akaike's criteria coupled with a nonlinear optimization scheme based on the probability plot to determine the optimal number of HFU present in the core dataset with the regression match giving the pertinent statistical parameters of each flow unit. Second, we cluster core data into its respective HFU by using the Bayes' rule. Finally, we apply an inversion algorithm based on Bayesian inference to predict permeability using only wireline data.
We illustrate the application of the procedure with a carbonate reservoir having extensive core data. The results showed the Bayesian-based clustering and inversion technique delivered permeability estimates in agreement with core data as well as with results obtained from pressure transient analysis.
Among the applications of the workflow presented are better productivity index assessments, enhanced petrophysical evaluations, and improved reservoir simulation models. Coupling of Nonlinear optimization with Bayesian inference proves a robust way for performing data clustering providing unbiased estimations
The objective of this paper is to share Occidental Oman's Talent Management strategies, development programs, and the results achieved on the ground. The focus will be on three major pillars; (i) understanding the adopted talent management strategies/framework and the value chain as we materialize the strategies on ground, (ii) hiring strategies, and (iii) ensuring we are developing the required talent development programs to accelerate the learning and time to autonomy. To give the audience a better understanding of our adopted talent management strategy and our sustainable nationalization program, I'll present one of the successful heavy oil projects as a business case, the Occidental Oman Block 53 Mukhaizna Project. Block 53 is a heavy-oil field (approximately 15.5 API). An oil field of such nature requires a unique set of technology and equipment to get the oil from the ground. Accordingly, Occidental Oman constructed one of the world's largest and most advanced mechanical vapor compressors, also known as MVC. Considering that Mukhaizna is the only MVC in the region, and taking into account the unique technology/equipment utilized in the project, there was an understandable lack of knowledge and expertise in the local and regional market. As a result, Occidental Oman had to develop a hiring and skills development strategy to be able to commission and operate the project to achieve the required targets.
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-Hinaai, Ahmed (Baker Hughes) | Al Esry, Saleh (Baker Hughes) | Scott, Dan E. (Baker Hughes) | Fuselier, Danielle (Baker Hughes) | Lee, Roger (Baker Hughes) | Boisvenue, Graham (Occidental of Oman Inc.)
Suppressed oil prices amid a call for increased returns from shareholders has created opportunities for operators and service companies to work closely in developing and deploying new technology in well construction efforts. Under extreme pressure, operators are seeking innovations to reduce drilling time and shorten the time to production. An operator in Oman has tripled output over the last ten years using enhanced oil recovery (EOR) methods, making it the largest independent oil producer in the Sultanate.
The development of polycrystalline diamond compacts (PDC) is one of the fastest-evolving technologies for fixed cutter drill bits. The application of PDC bits continues to expand performance by increasing rates of penetration (ROP) to lower drilling costs. The most recent developments in synthetic diamond cutters have been in 25mm-diameter cutters. Although 25mm-PDCs were developed in the mid-1990s, they lacked the necessary durability for demanding drilling applications. Only recently has the technology become available to meet these needs in this size.
Several recent tests in Oman have shown the new 25mm-cutter technology drastically improved performance with shoe-to-shoe runs at increased ROP. With the new cutters came the need for paired frame improvements with special considerations for aggressiveness and mechanical limitations for torque, both for the drilling rigs and use with positive displacement motors. During vertical drilling through carbonates and shales in the Diba field, the technology established a new field record ROP of 217 feet per hour—an 80% improvement over the field average ROP. In the Jalal field, 275 feet per hour was achieved—29% higher than the previous best record. The technology was also introduced on a steerable motor in a directional well, delivering improved penetration rates and excellent stability in slide mode. An additional lesson learned was the smooth torque generated by the large cutters. The smooth drilling torque enabled improved directional tool face control.
This operator has implemented an aggressive drilling and development program to drill faster and reduce cost per foot in heavy oil sands and fractured carbonates. The authors will present case studies to demonstrate how the latest technology 25mm-cutters and new frame technology helped lowered drilling costs for this operator's drilling program in Oman.