Kamkong, Paphitchaya (PTTEP) | Karnjanamuntana, Thamaporn (PTTEP) | Prungkwanmuang, Weera (PTTEP) | Yingyuen, Jakkrich (PTTEP) | Oatwaree, Dejasarn (PTTEP) | Amornpiyapong, Nichakorn (PTTEP) | Khositchaisri, Patcharin (PTTEP) | Tivayanonda, Vartit (PTTEP) | Wongsuvapich, Dutkamon (PTTEP) | Tongsuk, Soraya (PTTEP)
Lunar field is a marginal gas field located in the Gulf of Thailand. A significant portion of reservoir sands is currently categorized as Additional Zones of Interest (AZI) which is not accounted in reserves. As for this kind of sand, the conventional petrophysical evaluation alone cannot certainly distinguish between hydrocarbon and water in the porous medium. The alternative method (dT LogR) for formation re-evaluation is therefore considered in attempt to reduce uncertainty in fluid classification and reveal hidden hydrocarbon potential from these AZIs.
There are 2 phases in verifying the validity of dT LogR method. Phase I: dT logR method (Ref.
Phase II: The production test data from perforated AZIs in phase I and the well correlation were then incorporated in dT LogR assisted log reinterpretation. Additional 13 gas-potential AZI candidates were identified for 2nd perforation test to prove the correctness of the recalibrated petrophysical model. The results showed success in model improvement of which its accuracy increased to 61% and no high water production was observed in any of them.
After using dT LogR method to assist petrophysical evaluation, a total of 469 metres of unperforated AZIs were reconsidered to be productive gas bearing formation. In other words, 22 BCF of gas reserves and 873 MSTB of condensate reserves from these upgraded AZIs were added. In addition, it is foreseen that the remaining AZIs of other platforms are to be further reevaluated and therefore improves the confidence in reserves booking and field development planning of Lunar Field.
In conclusion, the dT LogR method is a very useful tool for Lunar Field to significantly reduce uncertainty of fluid classification which in turn provides lots of benefits in gas field management adding immeasurable value to Lunar Field.
Abdulhadi, Muhammad (Dialog Group Berhad) | Kueh, Pei Tze (Dialog Group Berhad) | Abdul Aziz, Shahrizal (Dialog Group Berhad) | Mansor, Najmi (Dialog Group Berhad) | Tran, Toan Van (Dialog Group Berhad) | Chin, Hon Voon (Dialog Group Berhad) | Jacobs, Steve (Halliburton Energy Services) | Muhd. Fadhil, Imran (PETRONAS Carigali Sdn. Bhd.) | Suggust, Alister Albert (PETRONAS Carigali Sdn. Bhd.) | Usop, Mohammad Zulfiqar (PETRONAS Carigali Sdn. Bhd.) | Ralphie, Benard (PETRONAS Carigali Sdn. Bhd.) | Dolah, Khairul Arifin (PETRONAS Carigali Sdn. Bhd.) | Abdussalam, Khomeini (PETRONAS Carigali Sdn. Bhd.) | Munandai, Hasim (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.)
It is a common practice to run a contact-saturation log to confirm the oil column prior to oil gain activities such as adding perforations or infill drilling. From 2012 to 2017, a total of eight logging jobs were executed in Field B which were subsequently followed by oil gain activities.
The eight contact-saturation logging jobs were comprised of pulse-neutron logs in both carbon-oxygen (C/O) and sigma mode. The logs were run in varied well completions targeting thirteen different zones. Four logs were run in single tubing strings while the remaining four were in dual string completions. Certain target zones were already perforated while others had completion accessories such as a blast joint or integrated tubing-conveyed perforating (iTCP) guns across them. Eight of the target zones were later add-perforated while two were used to mature infill well targets.
Four of the seven add-perforations results were consistent with the logging results. One of the successful logs clearly indicated that the oil column had migrated into the original gas cap. Of the two infill wells drilled, only one was successful. These case studies in Field B indicate that in conditions of open perforations, trapped fluid across the annulus, and in low resistivity sand, distinguishing between original and residual saturation is difficult with pulse-neutron log. The log measurement was significantly affected. The most obvious lesson learned was that perforating and producing the reservoir would be the best method to confirm the potential oil gain. From a value point of view, it would have been more economical to perforate the zone straightaway if the oil gain activity had similar cost to the logging activity. The lessons learned also helped to establish clear guidelines in Field B on utilizing contact-saturation logs in the future.
The paper seeks to present the logging results, subsequent oil gain activities, and lessons learned from the contact-saturation logging in Field B. These lessons learned will be applicable in other oilfields with similar conditions to improve decision making in the industry.
Pumping sand through coiled tubing (CT) with real-time capabilities is not a common practice because of potential risks associated with cable integrity. A successful sand plug settling procedure supported by a real-time fiber-optic integrated system under critical well conditions was of high importance during a recompletion intervention, allowing optimization of time and costs.
Multiple methods are used to isolate a well during recompletion activities; nevertheless, a cost-effective method to divert involves setting sand plugs with CT and a real-time fiber-optic integrated system, which is essential to achieving precise settlement of the sand, not just for depth but also for volume of sand pumped. Without this complete system, the operator would need to make extra runs for correlations with electric line (e-line) or CT units, which increases both cost and operational time.
A real-time fiber-optic integrated system allows adjustment to the sand plug stages in real time to help ensure top of sand (TS) necessary to isolate the producer formation and keep out the wireline entry guide without additional runs and increased costs.
A casing collar locator (CCL) tool permitted the correlation depth to be measured in each tag, ensuring knowledge of where the sand was placed and helping prevent incorrect depths resulting from uncontrollable factors, such as elongation.
More than 6,500 lbm of sand was pumped through CT using a real-time fiber-optic integrated system without losing communication with the downhole tools and without affecting cable integrity, which could lead to bird nesting the cable because of high friction and excessive slack inside the pipe.
This real-time fiber-optic integrated system begins a new generation of sand plug operations by helping prevent additional runs or having other units correlate, particularly if a recompletion activity is programmed and space accommodation is a challenge because of the workover unit.
The use of an electric drilling tool deployed on wireline is shown to be a safe, efficient and reliable method to penetrate the base pipe in sand screens. In the case study presented in this paper, a well on a field on the Norwegian Continental Shelf, completed with a Darcy sand screen that was clogged due to scale. A Darcy screen is an expandable hydraulically activated sand screen. An electric drill deployed on wireline was used to drill holes through the base pipe of the screen and into the flow channels to open for production. The tool needed a sufficient anchoring capacity for keeping the drill bit steady as well as accuracy of the drilling process to prevent damaging the underlying filter media. Both the anchor and the drill section of the drilling tool deployed are shown to be designed to meet these specifications. The sequence of the operation is presented, where two circular patterns at different depths with 13 holes each are drilled. At the time of publishing for this paper, the results on production from this operation is not yet known, as the well has not started producing again.
Green, Larrez (MDC Texas Energy) | Entzminger, David (MDC Texas Energy) | Tovar, David (MDC Texas Energy) | Alimahomed, Adnan (MDC Texas Energy) | Alimahomed, Farhan (Schlumberger) | Defeu, Cyrille (Schlumberger) | Malpani, Raj (Schlumberger)
Historically, vertical wells were used to correlate formation tops and determine the lateral continuity of the reservoir. With the advancements in horizontal drilling and logging, the industry is able to gather an immense amount of information about the rock as we drill farther away from the vertical section. Numerous industry publications indicate that approximately 40% of the perforation clusters in hydraulic fracturing do not contribute to production. Many factors play a role in such production behavior, but the most important factor is the breakdown of perforations and propagation of the hydraulic fractures through them. Several methods, such as limited entry design and placing perforations in similar type rock, have been applied to mitigate this problem; the information needed for these methods is obtained from logging the laterals or using drilling data to determine rock properties. Diagnostic tools such as production logs, permanent downhole fiber optics, radioactive tracers, and chemical tracers have been deployed to understand the varying production profiles seen across the unconventional reservoirs.
This study focuses on three wells with lateral measurements to obtain petrophysical and geomechanical rock properties (one well in the Wolfcamp B and two wells in the Wolfcamp A). The wells also had pseudo rock properties calculated using surface drilling data. In most instances, the perforation clusters in each stage were placed in good reservoir and completion quality rock with the aim to minimize the stress differential between clusters. Different perforation schemes were tested in each of the three wells - number of clusters and spacing, limited entry, and geometric design. The wellbore geosteering profile, whether in or out of zone, was also considered in relation to the subsurface structure.
Lateral measurements in all wells showed the changing lithology and rock types across the lateral. The Wolfcamp B had a production log that indicated twice as many clusters contributing in the section of engineered perforations compared to the section where the perforations were placed using the gamma ray log. Time-lapse chemical tracers in other wells indicated changing production profiles. For example, early in the life of a Wolfcamp A well, the stages with clusters picked based on logs showed the highest production contribution compared to the geometric stages, but, later, the trend started to shift in favor of the geometric clusters. The geometric stages were in an area of the wellbore where the carbonate content was highest.
Comparisons of various data sets to production performance, such as the one included in this study, will provide some insight into the heterogeneous nature of the Wolfcamp shale and the impact of varying perforation techniques on production contribution from individual clusters.
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.
Easy oil is no longer low hanging fruit for oil and gas operators, and drilling targets are becoming increasingly ambitious, which results in escalation of the well trajectory complexity. This accordingly spirals the well and completion costs. To overcome this situation, technology must play a role to reduce cost, increase efficiency and ensure safety at all times. Conveyance is the key for any data acquisition and well completion activities. Historically, conveyance methods for data acquisition and perforation in highly deviated or horizontal wells required drill pipe or coiled-tubing methods. These methods are time consuming, labor intensive, require a larger equipment footprint, with possible HSE risks involved. Mubadala Petroleum in Thailand has seen a significant increase in horizontal and high deviated wells over the past few years. The wireline tractor technology has been used for the first time in Mubadala Petroleum's Thailand operations during the drilling, initial completion and workover intervention operations, and it has been a game changer for Mubadala Petroleum in Thailand in terms of reducing rig time, well cost, and most importantly minimizing the HSE risks.
Over the past few decades, the oil and gas industry has developed the technique of drilling horizontally through the reservoir to maximize the surface contact area of the reservoir, to gain higher recovery and production. However, one downside from this technique is that it has become challenging and costly to perforate or to obtain measurements in this horizontal environment, as gravity will no longer support the wireline tools to reach to the bottom of the well. Wireline Tractor technology has played an important role to overcome this challenge. It reduces time, cost and will improve data quality as well as increase wellbore coverage. The wireline tractor functions with an electric over hydraulic power relationship, using its drive/wheel sections to push the passenger tool downhole as the cable is spooled off the unit allowing the tool to reach the end of horizontal or deviated wells without deploying drill pipe or coiled tubing conveyance methods. With this principle, any job that is typically run on electric wireline in a vertical well can be efficiently done in a horizontal or deviated well using wireline tractor.
Material presented in the paper will be from actual operations, examples being tractor conveyed wireline logging tool and 4.5in Outer Diameter (OD) 90 ft heavy long perforation gun in single tractor operations. It will also display the operational efficiencies increases and risk reduction being obtained.
Kabannik, Artem (Schlumberger) | Parkhonyuk, Sergey (Schlumberger) | Korkin, Roman (Schlumberger) | Litvinets, Fedor (Schlumberger) | Dunaeva, Anna (Schlumberger) | Nikolaev, Max (Schlumberger) | Usoltsev, Dmitry (Schlumberger)
Traditionally, surface pressure is the primary tool for onsite decision making during well stimulation treatments. In multi-stage wells with multiple injection points (perforation clusters) there are several available methods for diversion efficiency evaluation: differences in pumping pressure caused by pill pumping (also referred to as diversion pressure), instantaneous shut-in pressures (ISIPs) difference, and friction pressure difference. However, these techniques rely on interpretation of friction pressure or net pressure with uncertainties related to indirect measurements of the respective parameters.
A high-frequency pressure monitoring (HFPM) service uses specially designed hardware and proprietary signal processing algorithms to determine the true location of downhole events. Bayesian algorithms are used to calculate probabilities of the interval’s stimulation. Effectiveness and applicability of the method were tested on several wells across major US shale plays. It was demonstrated that the industry standard surface pressure techniques are not always the best approach for the on-site decision making. Even when diversion is not clearly visible, it still may occur downhole. Conversely, a significant diversion pressure response does not necessarily mean adequate diversion. The effective application of the HFPM technique makes engineered decisions more confident during stimulation and diversion operations.