Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
The paper discusses a petrophysical evaluation method for complex tight gas formations in a mature and partially depleted gas condensate field in Oman, allowing a full petrophyscial evaluation as well as geomechanical modeling from a source-less petrophysical dataset, thus reducing operational data acquisition risk in partially depleted reservoirs without compromising on hydraulic fracturing design. The developed methodology includes the volume of shale estimation from correlation with Poisson's ratio for the feldspathic rich tight formation. This methodology was used in deep tight fields in Oman for more than 3 years in both vertical and highly deviated wells greatly reducing the risk, logging cost and complexity of operations.
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.
Ibrahim, Ehab (Petroleum Development Oman) | Sayapov, Ernest (Petroleum Development Oman) | Hinai, Rashid (Petroleum Development Oman) | Qarni, Sulaiman (Petroleum Development Oman) | Kristanto, Royke (Petroleum Development Oman)
In low-permeability formations such as tight gas reservoirs, a well would be economic only if an effective hydraulic fracturing technique is selected. In central part of Sultanate of Oman a deep tight gas field is developed with hydraulic fracture stimulation. Normally, between 7 and 13 frac stages are done per well. Majority of wells are vertical with pay zones separated with shale layers that prevent fracture growth. Plug & perf is a common technique used in this field, therefore there are multiple well interventions during Hydraulic Fracture operations that consume time and delay the well delivery. 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. Equipment selection, design and development was performed based on well conditions, casing design, operational parameters and production gas composition.
Multistage frac completion allows the frac operation to be continuously performed without the need to conduct intervention activities such as running/setting frac plugs, perforating, milling and clean-out between intervals. The intervention activities can be conducted at the end of the frac operation in single-trip deployment if desired. The success in North America in horizontal tight gas wells has opened a door for implementation of this system in vertical wells in Sultanate of Oman. 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 might be easily missed. Besides, deployment and cementing operations are equally essential as proper zonal isolation is a must with water zones embedded in between.
This paper is discussing the lessons learned from utilization of multistage frac completion in vertical deep wells (around 5000 m) covering the completion and Hydraulic fracturing stimulation operations. This technique has proven significant cost & time reduction and production increase as well as reduced HSE exposure contributing to better gas recovery, improvement in operator's performance and energy delivery to the country.
Sayapov, Ernest (Petroleum Development Oman) | Al Farei, Ibrahim (Petroleum Development Oman) | Al Salmi, Masoud (Petroleum Development Oman) | Nunez, Alvaro (Petroleum Development Oman) | Al Shanfari, Abdulaziz (Petroleum Development Oman) | Al Gheilani, Hamdan (Petroleum Development Oman) | Smith, Andy (Welltec) | Yakovlev, Timofey (Welltec)
In recent years, horizontal drilling has become increasingly important to the oil and gas industry to enable efficient access to complex structures and marginal fields and to increase the reservoir contact area. New technologies have emerged during this time to address post-drilling intervention challenges in such wells. However, complexity of operations in horizontal wells is much higher than that of the vertical wells; therefore effectiveness of the selected technique has a major impact on the operational success and economics. In depressed market environment, economical and operational effectiveness becomes even more important especially when it’s down to complicated, challenging projects that require not only large investments but also simultaneous and continuous utilization of multiple resources, technical disciplines and assets. This paper reviews and compares different ways of horizontal multizonal well preparation for hydraulic fracture stimulation using plug & perf technique in challenging downhole conditions - differential pressures over 15,000 psi, presence of depleted zones complicating cleanout and milling operations between the frac stages, depth control issues.
In PDO, there are some gas fields sharing similar downhole conditions whereas fracturing operations are complicated by the requirement of CT cleanouts and/or milling in between the stages. A horizontal well development trial has been implemented to evaluate its economic efficiency and prospects. Depending on the success of this trial, this approach can be spread to other fields with similar characteristics. In these trial wells, multistage completion technologies were not available due to either differential pressure limitations, downhole conditions or completion restrictions, therefore conventional plug & perf approach had to be applied. Such approach, in turn, becomes very challenging in horizontal wells crossing several different formations having multiple severely depleted intervals along the wellbore. These challenges include not only cleanout efficiency and precise depth control during zonal isolation and perforation but also conveyance capabilities.
Several different techniques have been tried in PDO so as to discover the most efficient and economical way to complete this task: CT with deployed wireline cable, CT with fiber optic cable, DH tractors and conventional CT with GR-CCl tools in memory mode. All of them have their pros and cons and while saving some money in one small thing, a technique may cause major losses in the other and an operator needs to select the optimum approach taking into consideration multiple aspects.
All technologies covered in the paper are well known in the oil business; however some of them were tried in an uncommon environment. For example, although not commonly used in horizontal frac applications (except for perforating for the first stage), tractors were used for plug setting and perforating between the stages and that required well cleaned wellbore for each run which is not an easily achievable task in a horizontal wells with multiple depleted zones. With certain measures aimed to improve their performance, tractors proved their efficiency; these measures are also discussed in this paper. Advantages and disadvantages of CT conveyance in comparison to tractor have also been discussed.
E-line tractor technology has been successfully deployed in the Sultanate of Oman for reservoir surveillance using production logging assemblies in mature fields. Tractors provide specific advantages, as compared to other forms of conveyance, such as coiled tubing, and can successfully negotiate complex well trajectories in both horizontal openhole and cased hole well completions, enabling acquisition of good quality flow profiles in producers and injectors.
The presence of bitumen is an obvious risk for reservoir development. Pore-filling bitumen degrades reservoir quality. Sweetspotting, discriminating between producible oil and gas and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and the optimal development planning. However it is in most cases impossible to make such differentiation using conventional logs.
It is well known that the Nuclear Magnetic Resonance (NMR) log provides an opportunity to identify the presence of reservoir bitumen in oil bearing reservoirs. The zones containing bitumen within oil and water reservoirs are characterized by lower NMR porosity estimates when compared to porosity from the density and neutron tools. But in gas reservoirs, bitumen identification from NMR porosity deficit is not a common industry practice. The porosity deficit could be related not only to the presence of bitumen, but also to the presence of gas in the pore space.
The case studies include tight gas reservoirs in Miqrat and Middle Gharif formations, both located in the Sultanate of Oman. Well tests showed gas rates lower than expected, accompanied by low mobility and sometimes water production from intervals with relatively good porosity and saturation calculated from logs. Besides, bitumen was identified from core. A new methodology was developed which can differentiate between residual gas and bitumen presence based on Density, Neutron and NMR logs in conjunction with resistivity. One of the pre-requisites is that the reservoir lithology must be known. The remaining gas saturation is quantified from Density-Neutron separation. If we know the Hydrogen index (HI) of gas, the NMR porosity deficit can be compensated for residual gas effect. Bitumen saturation can be quantified from the difference of total porosity and NMR compensated porosity.
The methodology was tested on two tight gas reservoirs of the Sultanate of Oman. Core analysis, production data, and total organic carbon (TOC) derived from pulsed neutron logs were used to verify the results of the suggested methodology. The comparison shows that the methodology can be used for semi-qualitative identification of bitumen. It was also observed that the bitumen distribution varies across the field, and overall the majority of reservoir hydrocarbons are moveable. Recommendations on the workflow for static and dynamic modeling were provided.
The suggested novel approach of bitumen identification in gas bearing reservoirs is relatively simple. It provides fit for purpose results for gas bearing reservoirs including tight gas which in turn can be used for more accurate estimation of gas volumes and optimizing development planning.
BP is developing the Khazzan and Ghazeer fields of Block 61 in the Sultanate of Oman. The development includes three Cambro-Ordovician tight gas sand reservoirs which require hydraulic fracturing for commercial production rates. There are challenges with depth and high temperature for the open hole logging environment, with a restrictive inner diameter and residual proppant creating challenges for the cased hole logging environment. Additionally, there are cost challenges on all data acquisition including coring, downhole gauges, sampling, proppant tracers and many other forms of surveillance.
This paper outlines the evolution of the data acquisition strategy for the Khazzan and Ghazeer assets. The development plan at project sanction was 20 vertical and 272 horizontal wells. The data acquisition strategy led to the development of a data acquisition plan, and all stakeholders were engaged to ensure the right data was acquired in the right place at the right time. Cross functional behaviours and fiscal discipline were essential in this process. Inclusion of the service companies into the wider BP team was crucial to ensure appropriate technology was applied, learning from previous operations implemented and new technology options made available.
Through careful management of the data acquisition plan, all data in development wells prior to first gas were acquired within the allocated data acquisition budget despite drilling 20% more wells than originally planned for this period. Early improvement in subsurface understanding enabled an overall reduction in well count for the life of the project, extension of the original development into unpenetrated areas, adding significant value to the project.
The Amin formation is a tight sandstone formation, that is present in Block 61 in the Sultanate of Oman, that has presented a number of development challenges. The Amin reservoir is characterized by an average permeability approximately two orders of magnitude lower than the Barik formations, which is the other main current development reservoir within the field. Adding to the challenge is the presence of the immediately and extensively underlying Buah formation, which is known to be sour.
During the Appraisal phase of the project, two vertical wells and one horizontal well were completed in the Amin, demonstrating that a horizontal well profile with multi-stage fracturing would most likely be required to achieve consistently commercial rates. It was also evident, even during the project sanction, that significant further investigation would be required to be able to more completely understand the hydraulic fracture behaviour in the Amin; in terms of the created fracture geometry, appropriate hydraulic fracturing methodology, suitable formation connection techniques, and other completion design factors to succeed with a reservoir development. Additionally, it was known that understanding reservoir fluid distribution would be fundamental to delivering such wells.
During the Development phase several vertical wells were completed with a range of fracture types and designs, to facilitate an assessment of well performance in the vertical geometry, as well as understand the fracture height for various hydraulic fracturing techniques, including High Rate Water Fracturing (HRWF) treatments as well as Hybrid-Frac (HF) type approaches. Additionally, several horizontal wells were also completed to build upon the Basis of Design (BoD) that had been selected at the end of the Appraise phase, with a continuous learning approach taken to further develop the frac understanding. Lessons more recently learned from North American unconventional reservoir stimulations were also investigated, carefully selected and then subsequently applied in a coherent and systematic way.
This paper presents a review of several of these vertical wells and two horizontal wells, attempting to demonstrate the progress made between the approaches. Additionally, the two horizontal wells will be used as a case study to illustrate the application of the continuous improvement methods, as well as the adoption of some key appropriate technologies transferred from North American unconventional reservoir stimulation approaches. These included an investigation of perforation cluster efficiency, the baseline fracture design and fracturing fluid types; as well as integrating directly with the open-hole characterization and production logs to enhance the frac designs and results.
Miqrat is a complex clastic deep tight gas reservoir in the North of the Sultanate of Oman. The Lower unit of the Miqrat formation is feldspatic sand characterized by low permeability not exceeding 0.1 mD and porosity up to 12 %. Based on results of the appraisal campaign of Field X, it contains significant volume of gas. However the production test data after fraccing showed mixed results. The objective of this study to explain the production behavior in relation to the frac geometry.
Understanding the reason of possible overestimation of log derived Hydrocarbon saturation is important. Thus the interpretation of conventional and special logs was revisited. In parallel, all the available core data including SCAL and thin sections were dissected. Besides, the analysis of hydraulic fracture propagation, well tests, cement quality, PLT including Spectral Noise Log was performed.
The wells were subdivided into categories according to their production. wells producing no water wells with water channeling from the water leg of Middle Miqrat wells with transition zone intervals with two-phase inflow of water and gas.
wells producing no water
wells with water channeling from the water leg of Middle Miqrat
wells with transition zone intervals with two-phase inflow of water and gas.
There are three main challenges that needed to be overcome. First challenge is to identify the high uncertainty in hydrocarbon saturation from the resistivity logs. Petrophysical evaluation shows that porosity profile derived from logs looks very similar in all wells with insignificant lateral variations. Hydrocarbon saturation estimated from logs looks also similar regardless of how deep or shallow the well is. However, production tests show different results, e.g. different flow rates and high water-cut are observed in some wells.
The second challenge to keep the frac height below the boundary between Lower Miqrat and Middle Miqrat, which consist of around 3 to 7 meters of shale and in most of the field it is bound with water. The third one is to cover the upper part of the zone below the shale since it is the best part of Lower Miqrat without breaking to the water leg of Middle Miqrat. A geomechanical model was created and several frac model iterations were run since in the early appraisal well that boundary was broken.
Investigation through multidisciplinary integrated team led to unlock the tight gas reserves in Lower Miqrat. Based on open hole log interpretation to create a geomechanical model. That model is being calibrated with DFIT, 3 different case hole logs and confirmed with production.
The Barik formation is a low-permeability conventional tight-gas reservoir, in Block 61 in the Sultanate of Oman, comprised of a series of interbedded sandstone and mudstone (shale) layers. Such an approach was developed and deployed during the Appraisal stage of the programme and a considerable effort was placed in ensuring that the fracture height was contiguous, resulting in an effective drainage across all layers of the Barik formation. This approach was then encapsulated in the Full Field Development (FFD) planning Basis of Design (BoD) and was established as the approach to be taken throughout FFD. Until the field development was well underway, a single fracture treatment had proven sufficient to stimulate the entire Barik reservoir. However, as the development moved into the Southern area of the field, a substantial thickening of the Barik sequence was encountered and with this change successful complete vertical propped fracture coverage became much more challenging to achieve in an effective and repeatable manner.