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.
Hadidi, Shahab (Petroleum Development Oman) | Yaarubi, Hilal (Petroleum Development Oman) | Baaske, Uwe (Petroleum Development Oman) | Suwannathatsa, Sakharin (Petroleum Development Oman) | Farsi, Shadia (Petroleum Development Oman) | Bazalgette, Loic (Petroleum Development Oman) | Hamdoun, Lana (Petroleum Development Oman)
The infill potential of one of the most complex fractured carbonate reservoirs in the Sultanate of Oman has been evaluated through the integration, visualization and analysis of different data sources. The field has been split into different simplified genetic geobodies which contain the culmination of facies changes that define rock quality, fluid fill, oil saturation distribution and fracture network, amongst other properties that affect fluid flow. The long production history of more than 45 years, along with the large number of logged long horizontal wells scattered around the field, were key enabler for the analytical methodology.
Production data, coupled with resistivity logs in horizontal wells, viewed through time were the backbone of the analysis. Data analysis was achieved by combining these data in a single platform and performing the analysis at different slices of time. At each timeslice, different interpretations were inferred that explain the observed production behaviour and remaining oil saturation from the logged wells. The interpretations were narrowed down into a minimum number of realizations by combining interpretations from the same area gathered from different slices of time.
The analysis has resulted in the identification of four genetic performance regions in the field. Each region approximates a primary depositional facies belt and has a general defined relative behaviour of initial wells potential, water-cut development, initial and remaining oil saturation and, most importantly, infill wells potential. The analysis has aided in narrowing the subsurface uncertainties and has given a promising explanation for the large variations in wells behaviour. Infill wells opportunities have been identified, selected and ranked relatively in each of the regions.
The value of data analytics on large volumes of acquired information normally not used was demonstrated. Visualization of different data sources in one platform is a challenging task that usually stops engineers from experimenting. The team has found fit for purpose solutions to visualize different data sources through time. The shift of mind-set from uncertain complex models and evaluations into finding simple genetic performance regions of the reservoir was vital in unravelling infill potential.
Sayapov, Ernest (Petroleum Development Oman) | Nunez, Alvaro Javier (Petroleum Development Oman) | Al Salmi, Masoud (Petroleum Development Oman) | Al Farei, Ibrahim (Petroleum Development Oman) | Gheilani, Hamdan (Petroleum Development Oman) | Benchekor, Ahmed (Petroleum Development Oman) | Al-Shanfari, Abdul Aziz (Petroleum Development Oman)
Multistage frac completion (MFC) has been playing a significant role in modern oilfield industry being one of the key tools making development of low permeable formations economical. Commonly, it is applied in horizontal wells that are drilled to compensate for reduced drainage radius of these wells due to a lack of formation conductivity. This technique is evolving, there are quite a few inventions introduced every year that make MFC easier, more economical and that allow the operators to control and precisely evaluate both the treatment itself and performance of the created fractures. However, due to its nature and initial focus on horizontal wells, it did not become very popular in vertical wells. One of the reasons for it is its limited formation access since the sleeves that are providing the access are short and cannot cover the entire net pay. What historically more common in vertical wells are either conventional "plug and perf" approach or its modifications, whereas intervals are perforated with either coiled tubing and sand-blasting perforation or wireline guns, while isolation of the zones is achieved by setting frac plugs, sand plugs or frac packers depending on pumping conduits. In Petroleum Development Oman, some of these vertical wells were stimulated via multistage frac completion.
In central part of the Sultanate of Oman, a deep tight gas field is developed using hydraulic fracture stimulation technique since the formation conductivity is low and the near wellbore damage after drilling is making it even worse. Normally, between 6 and 13 frac intervals are stimulated in each well. Majority of wells are completed vertically with pay zones separated with strong shale layers that restrict fracture height development. Since plug & perf has been the main technique used in this field, there are multiple well interventions during hydraulic fracture operations that consume time, money and delay the well delivery. Moreover, the depletion of the field and its main productive zones make well intervention activities much more challenging whereas the risks of getting coiled tubing string or even wireline tools stuck in wellbore are high due to immediate losses faced after opening those low pressurized zones having as low as 8,000 KPa formation pressure, which can be 5-7 times less than hydrostatic pressures in the wellbore depending on depths and fluid s used. At the same time, with downhole temperatures ranging from 135 to 150 deg C and fracturing pressures reaching around 145,000 KPa bottomhole (~21,000 psi), differential pressures across the target zones can reach enormous levels of 15,000-20,000psi. Conditions in general become very risky, making it extremely difficult to source the right tools and equipment from what is available on the market. Another challenge associated with depletion of this field is an effective deliquification of the wells after stimulation treatments to allow them to effectively get rid of frac fluids and be able to produce gas to surface.
By deploying multistage frac completion with the objective of producing, enhancing and cost/time savings, the effectiveness of the fracturing operations was expected to increase. Multistage frac completion allows the frac operation to be continuously performed without the need to conduct well interventions such as running/setting frac plugs, perforating, milling and clean out between intervals. If needed so, the intervention activities can be completed after frac operations. Equipment selection and completion design were performed based on well conditions, market availabilities, operational parameters and composition of the produced gas. However, this technique is associated with its specific challenges that require attention and tailored solutions. The main challenge in deployment of this system in vertical wells is the accurate positioning of the sleeves. The shale layers between the pay zones could be as narrow as 5 m or less and a small pay zone can be easily missed. Besides, deployment and cementing operations are equally essential because of water zones embedded in between the pays.
This paper is discussing the recognized benefits and lessons learned from utilization of multistage frac completion in vertical deep (around 5000 m) depleted tight gas wells covering the completion and hydraulic fracturing stimulation operations. This technique has industry proven cost & time reduction and efficiency gain, as well as faster well cleanup and reduced HSE exposure contributing to better gas recovery, improvement in operator's performance and energy delivery to the country; it was expected to demonstrate a step change in the efficiency compared to conventional approach to the field development.
Polymer flooding has been identified as the next phase of developing two heavy oil fields located in the South of the Sultanate of Oman. The fields are supported with a strong bottom aquifer drive that results in large amount of water production due to the adverse mobility. In order to prove the concept of polymer sweep, a field trial was designed and conducted successfully in the field. Moreover, due to the challenges associated to handling back produced polymer number of tests were conducted to assess the impact of polymer on facilitates. Development of the field will take place in a phased manner in order to reduce the capex exposure, maximize the utilization of the existing facility and managing project risks while contributing to the overall production.
Dynamic modeling of both fields showed that polymer development is feasible. The modeling work was supported by a field trial that was designed to prove: polymer sweep performance, injectivity, as well as polymer losses to the strong water aquifer. This trial was monitored with detailed surveillance program including pressure, injection/production rates, viscosity and water quality, which concluded incremental oil gain from the process. In parallel, a number of laboratory and field tests were performed to assess the impact of polymer on the surface facilities such as the heater, separation tanks and the growth of the reed beds - wet planets- in the field.
Sustained incremental oil gain was clearly observed from polymer injection in the field trial. Injectivity could not be maintained as planned, due to a combination of polymer, biological and water quality issues. Later tests including biocide injection and QA/QC of polymer batches as well as some well stimulation did show improved injectivity profiles. Demulsifier tests mitigated the risk of creating stable emulsions. Laboratory tests indicated no heater fouling observed below 150°C. Short and long term investigation into the impact of water- contaminated polymer on plants in the wet lands was positive with the plants showing no necrosis. This was tested up to back produce polymer concentration levels of 500 ppm. Which is achievable given the excessive amount of water received at the facility allowing the dilution of back produced polymer to the required level. This helped in making the project more economically attractive as it results in a saving of around 30% from the overall project Capex.
The modeling exercise proposed drilling of around 200 polymer injectors across both fields, but in order to manage costs and further reduce project risks an optimised phased development approach was evaluated. Both Analytical and modeling approach were used to identify the phasing strategy. The phasing strategy will start with the most attractive to least attractive areas allowing for appraisal these areas prior to committing to their development. The key enabler for phasing of this development is by standardizing and replicating the development. Hence, modular facility for polymer preparation and injection was selected, in which a detailed design will be conducted for the first phase then it will be replicated for the other upcoming phases.
Phase-1 of the development will be in the central area as it is has a better response from the model compared to the other areas. This phase will include the drilling of 25 injectors and it will require two modular facilities. 25 to 30 injectors will subsequently be drilled every 2 years for the follow up phases.
The different surface and subsurface tests paved the way for a full field implementation of polymer injection in structures with strong bottom water aquifer. The paper discusses the phasing and replication strategy to mitigate project risks, learn on the go and improve the project’s schedules and economics.
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.
Al Mamari, H. A. (Petroleum Development Oman)
PCP population in PDO fields is around 18% of the total Artificial Lift systems with an average runlife of around 360 days. The main cause of failure are tubing leak and sand resulting in parted rods & pump stuck. Continuous PCP surveillance/ monitoring are key to understand pump performance and hence increase their runlife. With this objective, PDO has installed a PCP Controller application / surveillance tool called Well Manager in number of wells on trial basis. In the current set up, PCPs are operated using speed mode and the fluid level checked occasionally using simple fluid shot apparatus whereas with Well Manager they can be operated using different function like production optimization mode, dynamic fluid level or speed control mode all of these modes can be associated with de-sanding function or torque limiting function. These modes to be functional require running downhole gauge, casing pressure, flow line pressure and surface flow rate meters. Surveillance data collected from these meters while these modes are activated has allowed PCPs to automatically optimize their operating conditions to prevent trip due to sand accumulation and pump stuck and therefore increase runlife time. New PCP setup was installed in well No.1 aiming to reduce solids whilst keeping production rate as it was expected. Well Manager with automated flushing feature every 8 hours, and down hole gauge installed with ant-vibration sub has led for doubling the run life and eliminating FBU interventions. This has resulted in increasing run life from 113 to 239 days and still running. Moreover, compared to the old design in this well, the new set up managed to produce same flow rate using a smaller pump size with lower solids production rate. Another four units installed and showing positive results as well as stability with less well trips and increase in run life. The novelty and combination of the Well Manager set up can be replicated and implemented in all PCP wells in the oil industry helping to increase pumps runlife, reduce well intervention cost and oil deferment and therefore, reducing the life cycle cost.
PCP population in PDO fields is around 18% of the total Artificial Lift systems with an average runlife of around 360 days. The main cause of failure are tubing leak and sand resulting in parted rods & pump stuck. Continuous PCP surveillance/ monitoring are key to understand pump performance and hence increase their runlife. With this objective, PDO has installed a PCP Controller application / surveillance tool called Well Manager in number of wells on trial basis.
In the current set up, PCPs are operated using speed mode and the fluid level checked occasionally using simple fluid shot apparatus whereas with Well Manager they can be operated using different function like production optimization mode, dynamic fluid level or speed control mode all of these modes can be associated with de-sanding function or torque limiting function. These modes to be functional require running downhole gauge, casing pressure, flow line pressure and surface flow rate meters. Surveillance data collected from these meters while these modes are activated has allowed PCPs to automatically optimize their operating conditions to prevent trip due to sand accumulation and pump stuck and therefore increase runlife time.
New PCP setup was installed in well No.1 aiming to reduce solids whilst keeping production rate as it was expected. Well Manager with automated flushing feature every 8 hours, and down hole gauge installed with ant-vibration sub has led for doubling the run life and eliminating FBU interventions. This has resulted in increasing run life from 113 to 239 days and still running. Moreover, compared to the old design in this well, the new set up managed to produce same flow rate using a smaller pump size with lower solids production rate. Another four units installed and showing positive results as well as stability with less well trips and increase in run life.
The novelty and combination of the Well Manager set up can be replicated and implemented in all PCP wells in the oil industry helping to increase pumps runlife, reduce well intervention cost and oil deferment and therefore, reducing the life cycle cost.
This paper will describe a methodology which has been developed as an alternative to four-dimensional (4D) Seismic. The main objective is to track heat conformance over time in the thermally developed "A" Field, Sultanate of Oman. The method has several significant advantages over 4D Seismic, including: Negligible cost and manpower requirements; Provision of close to real-time information and no processing time requirements; No Health, Safety or Environmental exposure, or disruption to ongoing operations.
Negligible cost and manpower requirements;
Provision of close to real-time information and no processing time requirements;
No Health, Safety or Environmental exposure, or disruption to ongoing operations.
The paper will also demonstrate the power of integrating wide-ranging data sources for effective well and reservoir management.
The increasingly close well spacing at "A" Field has made Seismic Acquisition progressively more challenging. Conversely, it has created an opportunity to utilize dynamic Tubing-Head Temperatures (THTs) for tracking areal thermal conformance over time. For each month in turn an automated workflow:- Grids the monthly THT averages; Integrates the production and injection data, represented as bubble plot overlays; Adds the top reservoir structure from the subsurface model, highlighting structural dip, and fault locations.
Grids the monthly THT averages;
Integrates the production and injection data, represented as bubble plot overlays;
Adds the top reservoir structure from the subsurface model, highlighting structural dip, and fault locations.
Morphing (movie) software then interpolates the monthly images to create a smoothly transitioning "Heat Movie".
The Heat Movie demonstrates the general effectiveness of the Development in terms of warming the reservoir over time. This in turn is reducing the oil viscosity and increasing production. However, it also highlights temperature anomalies that can be linked to geological features such as faults and high permeability layers. Identification of these anomalies may underpin decisions to optimise the thermal development.
In addition to the Movie, time-lapse images can be created for any chosen period. This is similar to 4D Seismic, but more powerful, since the period can be directly linked to significant field milestones, for example equal time periods before and after upgrading the steam generation process.
Proof of Concept was demonstrated in early 2018, and the technique has already been deemed sufficiently mature to utilize it for tracking and managing Thermal Conformance in place of 4D Seismic. This is resulting in annual cost savings of millions of dollars and man-years of staff time.
One potential advantage of 4D Seismic is highlighting vertical conformance. Although this is not possible using THTs alone, at "A" Field the plan is to mitigate this by integrating data from ongoing Distributed Temperature Sensing (DTS) and well temperature surveys.
Regarding applicability, the workflow can be adapted for other objectives, for example creating a movie of surface uplift and/or subsidence integrated with bubble plots of production and injection data, or water breakthrough for wells with downhole gauges, in water flood developments.
In addition to describing the methodology underpinning this innovative approach, this paper will also discuss the vision for further improving the workflow and expanding the functionality.
This paper discusses KSI project which is the first in-house study on QA Cluster, aimed to accelerate delivery. This abstract spotlights the surface & subsurface integrated work results on fast track from DG1 to FID within 1.5 years by utilizing data from analogue fields & replication of surface concept & facility design.
For the subsurface, an extensive analogue study was conducted. Then simple 1D analytical model used to generate well by well forecast. A small box model constructed to test different water flood development sensitivity & define the optimum spacing, type of pattern & water injection depth where the outcome compared with 3D simulation model & they match.
For the surface, a small Well Test Unit (WTU) is leased to maximize the oil production from KSI field & provide an early view of reservoir waterflood uncertainty. The full field surface facility concept is a replication from H analogue field. This replication leads to accelerate the on stream date by 24 months.
KSI is a green field which is one of the Lower Shuaiba pancake reservoir where it transferred from exploration with a high UTC project & very long schedule.
It was identified that the key critical success factors are accelerating initial oil production & reducing Capex by using analogue field data, optimized phased-development, replication for facility design, & optimized well design & well spacing.
Comparing the KSI field with analogue fields, resulted on chosen a line-derive waterflood as development concept which was validated by running a box model.
The good match achieved between 1D analytical model used at DG2 & 3D simulation model used at DG3 indicated that the analytical model is sufficient as promise for Field
Development Plan (FDP). However the numerical model will be needed for easily future waterflood management.
Changing the well completion design from single horizontal to dual lateral is resulted in reducing the CAPEX (Drillex) by 54%. The replication of surface facility resulted on achieving two years ahead of initial schedule.
The in-house study & replication of surface facility led to reduce the total project CAPEX 7%, increase NPV by 77%, reduce the project UTC by 21% & accelerated the schedule by 2 years as below
Full field polymer flood has been identified as a potential EOR process for a heavy oil field with a strong bottom aquifer in the South of the Sultanate of Oman. A number of surface and subsurface risks have been identified prior to field implementation, including matrix injectivity, polymer sweep and impact of back produced polymer on surface facility & the field wet lands (reed beds). The development of the field will take a place in a phased manner in order to reduce the capex exposure, maximize the utilization of existing facility and managing project risks while contributing to the overall production. In order to support the standardization and steer the future phases the modular facility concept was selected as basis for polymer preparation and injection facilities, this design was made flexible enough to cater for a wide range of possible trial outcomes.
A very comprehensive polymer pilot was performed in this dome-shaped heavy oil reservoir to assess polymer sweep performance as well as losses to the strong water aquifer. An inclusive real-time surveillance programme was executed to monitor key parameters including pressure, injection/production rates, viscosity and water quality, which concluded incremental oil gain from the process. Other tests were conducted to assess the impact of back produced polymer on growth of plants, heater fouling and surface facility separation tanks. In general, all results were positive which paved the way for field-wide development of polymer flooding with less Capex requirement.
A sustained incremental oil gain was clearly observed from polymer injection, which was supported by saturation logs acquired from the observation wells. Injectivity could not be maintained as planned, due to a combination of polymer, biological and water quality issues. Later tests including biocide injection and QA/QC of polymer batches as well as some well stimulation did show improved injectivity profiles. Demulsifier tests mitigated the risk of creating stable emulsions. Lab tests indicated no heater fouling observed below 150°Cdeg. Short and long term investigation into the impact of water-contaminated polymer on plants in the wet lands was positive with the plants showing no necrosis with back produced polymer concentrations up to 500 ppm which is achievable given the excessive amount of water received at the facility level that dilute the back produced polymer. This helped in making the project more economically attractive as it results of a saving of around 30% from the overall project Capex.
The different surface and subsurface tests paved the way for a full field implementation of polymer injection in structures with strong bottom water aquifer. The paper discusses the phasing that was purused to mitigate risks, learn on the go and improve the project economics
The subject field (Field NG) is one of the largest matured oil accumulations located in the South of Oman Salt Basin. Production and integrity issues have been the main challenge in recent years, manifesting in abnormal behavior of water-cut with time. Hence, detailed technical multidisciplinary studies were conducted in order to identify causes and propose mitigations.
The base historical performance of the field showed water cut progression behaving as a matrix block, however, in recent years new wells started showing unexpectedly higher initial water production (fracture like behavior). A thorough investigation was carried out utilizing numerical simulation models calibrated to Field NG production history in order to characterize the type of rock behavior (matrix behavior, conductive streaks, fractures, faults, etc). The study concluded that the water cut behavior was due to naturally-occurring fractures which are limited in length and not vertically extensive. During the early stages of production, when the initial water-cut shows matrix like behavior, the bottom water is not in contact with the fracture network. However, after years of production and rise of the water table, the fracture behavior became dominant as the water gets in contact with the small vertical fractures. The presence of these fractures were confirmed by a total of 11 FMI data taken since 2015.
The proposed solutions included detecting fractures early on using bore-hole imaging techniques and utilizing EZIPS in sealing as many fractures as possible. This completion method resulted in delayed water production and increased NPV by 2-3 $MM per well. Moreover, new and efficient WRFM technologies such as Autonomous Inflow Control Devices (AICDs) have been deployed in horizontal wells which selectively limit water flow. Initial results from the early implementations of AICDs are very encouraging.