This paper provides technical feedback of a successful use of Directional Casing While Drilling (D-CwD), a technique allowing to simultaneously drill and case the hole while following the directional plan. It highlights how substantial gains were realized on Badamyar project in Myanmar, having benefited from the D-CwD technique to optimize the architecture.
The Badamyar development campaign involved the drilling of four horizontal gas wells in conventional offshore environment in Myanmar. Other regional wells had already experienced wellbore issues to get the 13 3/8″ casing vertically to 450m. On Badamyar, drilling directly with the casing allowed to minimize operational exposure to losses and wellbore instability, and to achieve the challenge to get the 13 3/8″ to 800m and 45deg inclination, avoiding the requirement for an additional surface casing.
All four 13 3/8" sections were successfully directionally casing-drilled and cemented in fourteen days within budget duration, which, despite the additional complexity, is comparable to the best performance in the block in the last twenty years. The average Rate of Penetration was 30 m/hr, same as fastest conventional case in the field, without mentioning the huge advantage that when reaching the required depth, the casing is already in the hole. Indeed, once the casing has reached the required depth, drill pipe is run inside the casing to unlatch and recover the directional BHA, and pull it back to surface, leaving the casing in place ready for the cement job. While conventionally, casing still needs to be run with associated time and risks (losses, wellbore stability, stuck casing, accidental side-track, etc…).
This Directional-CwD was a new concept to most of the teams involved: Operator, Rig contractor and Tubular Running Services. It required changing the "hundred and thirty years of conventional drill-pipe drilling" mindset. This paper describes the decision making process to switch from conventional to casing-drilling, the preparation phase where risks were identified and mitigated, as well as the excellent operational results.
This paper, by presenting a successful first implementation within a major O&G company, brings to the drilling industry an additional case that the system works, is technically fit-for purpose, cost effective, and has the tremendous potential to replace conventional drilling in several applications. It also highlights some potential limits and opportunities for optimization which should be considered for further development (trajectory constraints, fatigue life and well control).
Hillier, Jill (Schlumberger) | Guedes, Carlos Eduardo (Schlumberger) | Baumann, Carlos (Schlumberger) | Torres, Abraham (Schlumberger) | Sarian, Serko (Schlumberger) | Aboelnaga, Sharif (Schlumberger)
The perforating deployment system significantly reduces rig time while maximizing the perforation length per run as compared with traditional systems, both on land and offshore, for rig or rigless interventions with very limited rig-up height.
In limited rig-up height interventions, such as installations with short rig-up height or small cranes, to perforate long intervals it is necessary to use multiple short gun runs. To reduce the number of runs, short gun subassemblies are connected using a sealed ballistic transfer connector. The sealed ballistic transfer connector provides surface wellhead pressure containment sealing capability within the gunstring while also ensuring downhole ballistic transfer between guns subassemblies and the added value of optimizing perforating underbalance conditions. There is no limit on the number of sealed ballistic transfer connectors that can be used in one string. The sealed ballistic transfer connector allows deployment and reverse deployment under pressure in wells up to 103 Mpa, and it is qualified for H2S environments.
The application of this technology allows significant rig-time savings and reduces personnel exposure via a remote operational console that enables personnel to connect and disconnect the guns under pressure from a safer distance. To date many jobs have been completed with this proven technology. One example presented in this paper is a horizontal well perforated from an offshore installation with an extremely short rig-up height, where there was only 16 m available to deploy wireline toolstrings. The limited height meant that a conventional wireline with tractor would allow deploying only a single 6-m-long gun carrier per trip. Using sealed ballistic transfer connectors enabled a 53-m gunstring (seven 6-m and one 3-m carrier plus adaptations) to be deployed in a single run using eight sealed ballistic transfer connectors. This was a record for the deployment conditions. More than 100 deployment and reverse deployment insertions were successfully conducted during this perforating job, reducing the required number of wireline runs from 59 to 10, and saving 51 days of operation and rig time.
This paper demonstrates how the integrated application of the perforating sealed ballistic transfer connector technology, tractors, and polymer-encapsulated cables can reduce time in long perforating jobs with short rig-up heights both on land and offshore. In another presented example, the operator saved days of rig time, in addition to large economic and production time savings, and also reduced the exposure of personnel to lengthy, riskier tasks.
Located in the Arabian gulf, the Qatari North Field is the largest non-associated gas field worldwide with estimated reserves exceeding 900 trillion cubic feet of recoverable gas, or approximately 10% of the world's known reserves. Development of this field present tough conditions for all aspects of well drilling and completion activities. Particular challenges for performing well intervention, which have driven operators and manufacturing and service companies to develop innovative strategies and systematic technology collaboration for intervening these fields in a safe and efficient manner.
Recently, two new sub-horizontal wells with multiple reservoir zones needed to be perforated and selectively stimulated. Considering safety factors and operational efficiency, the insertion and retrieval under pressure system was identified as the best alternative to convey an average length of 600ft of 2 7/8-in. guns in single trips with coiled tubing (CT). Although this system has been successfully used in other regions, downhole adverse conditions required specifc components and implementing innovative methods, including the use of 5/16-in. braided slickline for gun deployment, and 2 3/8-in. CT with fiber optic telemetry capability for accurate depth correlation, precise actuation of the firing head system and confirmation of gun detonation.
As result of a dedicated planning and preparation process, the two wells were perforated in controlled conditions and each of the applied technologies proved its value. The use of 5/16-in. braided slickline reduced the gun deployment time by at least 2 days from the planned schedule, and the H2S rated connectors and the pressure-pulse firing head gave the confidence to avoid any issues when the perforating assembly was downhole. In respect to the CT real-time telemetry system, this technology provided an exceptional indication of bottomhole conditions throughtout the operation by enabling precise control of the firing head mechanism, identification of gas/water fluid contact in the well, and monitoring of formation response, which eliminated the need for initially planned nitrogen lift operations.
This paper describes the selection process of the key technologies deployed for performing CT conveyed perforating operations in two sub-horizontal wells in Qatari North Field, and discusses the workflow developed for those interventions. It then presents case studies and lessons learned and provides conclusions from the experiences gained for performing CT conveyed perforating operations in North Field.
Waterflooding through water Injection is one of the most effective secondary method to improve oil recovery. Integrated water injection management comprises managing the performance at the reservoir, the wells and the surface and their interdependencies. Lack of effective management of any of these would pose serious concern on incremental recovery due to water injection. Although, water injection (WI) has been in place for many decades, a comprehensive technique to measure the integrated performance of the water injection due to better subsurface management, and/or well management, and/or surface WIM management is not well-established in the industry. Thus it is very difficult to evaluate and compare overall performance of a WI project with the efficiency of other WI projects. In the current times of limited CAPEX spending, thus a technique is required to evaluate various WI projects under the same yardstick, so as to decide on which project more money need to be spent for better returns. Such yardstick which evaluates each of the WI modules (WIM) of subsurface, wells, facilities WIM helps thus then to consider optimal remedial measures to attain excellence. This paper explains how an easy, doable and effective method to evaluate WI performance was generated with help of Key Performance Indicators of the subsurface, wells and surface facilities for a WI project.
This paper reviews the processes which affects the WI performance and identifies Key performance areas (KPA) of influence during Water injection stage. On the basis of merit and impact of each KPA on the overall effectiveness of WI, performance Indexing has been attempted to generate Key Performance Indicators (KPI) in an innovative manner. All KPIs are integrated together with respective weightage factor derived from their individual influence on WI performance into an overall performance indicator. An integrated surface-to-wells-to-subsurface system optimization has been the key consideration during the development of this technique. A worksheet with inbuilt formulae leading to the estimation of all Key Performance Indicators and Overall indicator has been constructed to be used for any WI projects with option of related data inputs. It has been tested on real data of few offshore fields of PETRONAS as sample test and proved to be a valid indicator of WI performance. To test the robustness of the tool it was blind tested by taking out the data of some key injectors in one of the better water flooded reservoirs.
This tool has thus proved effective to gauge the performance of a WI project, remains a measure to compare and rank performance with respect to other WI projects. A continuous plot of the KPIs helps to identify the concerned areas for possible improvement. This technique is thus capable of diagnosing all sub-optimal areas within a WI project simultaneously, which when addressed leads to operational excellence and improvement in oil recovery. Recent usage of this tool to rank WI performance of different projects helped to initiate competition between different operators for improvement.
Zakwan, M. (Petroliam Nasional Berhad, PETRONAS) | Sahak, M. (Petroliam Nasional Berhad, PETRONAS) | Aris, M. Shiraz (Petroliam Nasional Berhad, PETRONAS) | Ariff, Idzham F. M. (Petroliam Nasional Berhad, PETRONAS) | Saadon, Shazleen (Petroliam Nasional Berhad, PETRONAS) | Muhammad, M. Fadhli (Petroliam Nasional Berhad, PETRONAS) | Radi, N. M. (Petroliam Nasional Berhad, PETRONAS) | Daud, N. M. (Petroliam Nasional Berhad, PETRONAS)
The injection of chemicals in a chemical enhanced oil recovery (CEOR) program is expected to impose technical and economic challenges in produced water management especially for offshore installations. The breakthrough of injection chemicals into the surface facilities process lineup, through the water phase, have been tested to be toxic and the typical overboard discharge option will have to be substituted with a much more complex and expensive reinjection scheme if a solution to treat the discharge water is not found. A study to find a chemical treatment solution capable of degrading the toxic components in CEOR produced water was carried out and upscaled towards a pilot implementation for an offshore Malaysian field. The advanced oxidation process (AOP) technique was evaluated as it showed promising capabilities for the intended application. The governing degradation mechanism in the AOP stems from the release of hydroxyl radicals from hydrogen peroxide (H2O2), with the aid of UV radiation, which oxidizes organic components in the injected chemicals to detoxify the outlet stream of the surface facilities process. The results from the experiments showed promising degradation potential where complete degradation of the toxic chemicals was achieved. Specific degradation rates of the chemicals at fixed rates of UV radiation were obtained in this study and used with the electrical energy per order (EE/O) upscaling correlation to size a treatment system for the intended pilot implementation. Compared to other established chemical degradation applications, the upscaling EEO value of 17.9 kWh/1000 USgal/order can be considered to be within reasonable range.
Zhang, Guowen (Research Institute of Petroleum Exploration & Development) | Qian, Jie (Research Institute of Petroleum Exploration & Development) | Shen, Zejun (Research Institute of Petroleum Exploration & Development) | Zhang, Weiping (Research Institute of Petroleum Exploration & Development) | Xue, Jianjun (Research Institute of Petroleum Exploration & Development) | Huang, Peng (Research Institute of Petroleum Exploration & Development) | Liao, Chenlong (Research Institute of Petroleum Exploration & Development)
Most of horizontal wells was completed with uncemented screens to prevent from sand production in some oilfields near Bohai Bay east China. In recent years oil production of the wells have begun to decline due to water out of the wells, especially water rates in part of the wells were more than 98%. Finally higher water out resulted in the wells to be closed. A technique of water shut-off was developed. First of all, a tools string for chemical agent injection (TSCAI) was run into the wellbore. The chemical agent was injected into the annular space between the screens and the formation to form annular chemical packers (ACP). So the ACP could separate the formation into several sections to avoid annular communication. Secondly, a liner hanger with sliding switches and swelling packers (LHSSP) was run after TSCAI was pulled out of the well. The liner hanger was released after the packers were set. Finally a mechanical on-off element for the sleeves with coiled tubing string (ESCTS) was run to open\close the switches separately. By analyzing the well production date the operators determine that which layer water ed out. The ESCTS was run to closed water out layer. Well-A was a horizontal well drilled in 2006 in the Gaoqianbei zone of Jidong Oilfield. In 2010 production logging date showed that water content was 98.7%. A water shut-off action was done. The whole horizontal interval was separated three sections (No.1, No.2, No.3 layer). Finally after No.1 layer was confirmed to be water cut layer to be closed, daily oil production was improved from 2 tons to 4 tons. Water content reduced to 70.9%. Generally, the successful water shut-off for well-A showed that the technique could efficiently enhance oil recovery with simple operation and low cost. It provides a new water shut-off method for other wells with different completions.
In order to improve wells production, the most of wells were completed as horizontal wells since 2003 in Jidong Oilfield in China. The Oilfield is located in the west coast of Bohai Sea Gulf in China. Because horizontal well increase the contact area with reservoir, average output of horizontal well is 2 - 3 times higher than that of vertical well in same oil zone. Water cut in horizontal wells has become more and more serious after the wells developed several years. Oil production of the wells has begun to decline due to water out of the wells, especially water rates in part of the wells were more than 98% in recent years. Finally higher water out resulted in the wells to be closed. So how to solve water out in the wells has become primary problem in Jidong Oilfield.
Kalwar, S. A. (Weatherford Oil Tool Middle East) | Elraies, K. A. (Universiti Teknologi Petronas) | Abbas, G. (Mehran University of Engineering & Technology) | Kumar, S. (Mari Petroleum Company Limited) | Farouque, K. (Weatherford Oil Tool Middle East)
Alkali-Surfactant-Polymer (ASP) flooding is the most effective Chemical Enhanced Oil Recovery (CEOR) method applied in sandstone reservoirs. After the successful results in sandstone formations, its usage has been widened to carbonate reservoirs as well. However, ASP application in carbonate reservoirs is less well understood. The main limitation of ASP flooding in carbonate reservoirs is the presence of carbonate minerals. These minerals react with the added chemicals to form insoluble materials called precipitations. Therefore, an ASP formulation was developed by incorporating acrylic acid as a precipitation inhibitor to overcome the precipitation problems.
The performance of the Acrylic Acid (AA) with an ASP formulation was evaluated using sodium metaborate, surfactant and polymer. Feasibility of applying AA with ASP formula was demonstrated by comprehensive fluid-fluid compatibility tests, interfacial tension tests, viscosity measurements and coreflooding experiments. Hardbrine composition of 59,940 ppm was used to prepare the ASP formulations in the presence and absence of AA. All the chemicals including, alkalis, surfactants, and polymers were compatible with the hard brine used in this study. The presence of acrylic acid exhibited excellent properties in preventing precipitations as the all solutions remained clear for 30 days at 80 oC.
The weight ratio of optimum acid concentration of acid to alkali was found to be 0.6:1.0. No precipitation was observed when using this acid to alkali ratio. Interfacial tension and viscosity tests screened the best chemical formulations which were validated by coreflooding. The core flooding tests showed significant improvement in the oil recovery with the use of AASP and ASP flooding by accomplishing a total oil recovery of 75.7% and 88.7% OOIP respectively.
Although, total recovery efficiency of AASP formulation is relatively lower than with ASP, the new AASP formulation can be prepared with any water source such as formation water or seawater. The precipitation inhibitor makes the conventional ASP system more flexible and advantageous for offshore applications by eliminating the need of softening or desalting the seawater. Furthermore, there is no need to remove the calcium and magnesium ions from the injected water as it can be done by using the appropriate concentration of acid and alkali. This eliminates the cost of water treatment equipment and minimizes the use of surface equipment as well.
Well completion and commissioning operations offshore present a variety of technical and operational challenges in the quest to maximize well productivity and optimize the economic value together with focus on safety. This is very relevant to perforation operations performed in hostile and high-pressure reservoir conditions encountered in a complex development project in the Caspian basin. The degree of complexity is increased due to required oriented perforation in a deviated intelligent completion well equipped with well monitoring system mounted on the outer side of the production liner. We describe the developed innovative technical solution for oriented perforation, challenges encountered, lessons learned, and results of this first-time-in-the-world implementation.
To meet job objectives, we selected electric-line enabled (e-line enabled) coiled tubing (CT) for precise depth control, the latest-generation advanced gun deployment system (15,000-psi working pressure 5.12-in. ID H2S-rated) for conveyance of long gunstrings under pressure paired with specially developed hostile oriented gun system, and newly designed CT perforation string components, such as the perforation-shock-resistant bottomhole assembly (BHA), two independent emergency disconnects, high-tensile CT logging head disconnect weak points, perforation passive casing orienting device, and tuned software to predict and evaluate shock load and dynamic underbalance.
The oriented perforation job was successfully completed with this innovative oriented method for perforation applications—passive casing orienting device for deviated wells. This perforation technique proved capable of providing desired orientation accuracy and effectively minimized operational time and associated risks. Such approach allowed safe and efficient perforation in a controlled well environment and provided perforation in the desired direction away from downhole well monitoring equipment and with accurate depth control, and managed detonation shock load in overbalanced conditions, which avoided any well fluid influx or H2S release. The developed solution is a seamless integration of e-line enabled CT, the CT logging head, a gun deployment system for pressurized well conditions, and a set of wireline tools and specialized perforation equipment for passive orientation.
This is the first time that the described oriented CT perforation operation using such innovative techniques has been performed in the world. The experience demonstrates a method to safely and efficiently facilitate challenging oriented perforation jobs in the future for intelligent completion applications and a great opportunity for well performance evaluation through distributed temperature-sensing analysis.
Well commissioning operations offshore encounter multiple organizational, operational and technical challenges that must be safely overcome to efficiently deliver high-quality service. Coiled tubing (CT) perforation and commissioning performed in hostile reservoir conditions and high pressure is one of the most complicated multiservice operations, especially in a sensitive aquifer ecosystem like the shallow Caspian basin. A comprehensive approach used to deploy an innovative solution to the challenges provided experience in such operations and lessons learned.
An innovative perforation technique was selected for the project: electric-line-enabled CT for precise depth control in combination with an advanced gun deployment system for conveyance of long gun strings under pressure. New techniques were incorporated to improve equipment efficiency and reliability: detonation shock-resistant bottomhole assembly, two independent emergency disconnects, software to predict and evaluate shock load and dynamic underbalance, high-pressure H2S-rated and conventional connectors for a specialized tool deployment stack (TDS), rounded scallop guns, and high-tensile CT logging-head-disconnect weak points.
To date, more than 10 well commissioning operations were successfully completed with this innovative method. Integrated service project management was a key approach to achieving successful results by effectively integrating multiple service lines. The technique proved to effectively minimize operational time, associated risks, improper equipment use, and interface failures between different service lines. The developed solution is a seamless integration of electric-line-enabled CT, the CT logging head, the gun deployment system for pressurized well conditions, and a set of wireline tools and specialized perforation equipment. The design was optimized to perforate the well in three or four runs at overbalanced condition (squeeze mode) in one rig-up job instead of the more than 20 wireline runs typical in conventional operations. Additionally, the use of CT provided the flexibility to perform pumping operations for well displacement, injection of an H2S scavenger, and stimulation, as per the operator's plan, without or with only partial rig-down.
This was the first time that integrated service project with the described CT perforation technique was performed in the Caspian region. The acquired experience will facilitate design, preparation, and execution stages for such type of jobs with multiple services involved.
Well completion and commissioning operations offshore present a variety of technical and operational challenges in the quest to maximize well productivity and optimize the economic value together with focus on safety. This is very relevant to the perforation operations performed in hostile and high-pressure reservoir conditions encountered in a complex development project in the Caspian basin. We provide description of the project and the innovative solution applied, including challenges faced, experience gained, and lessons learned.
To overcome challenges, we selected electric-line-enabled (e-line-enabled) coiled tubing (CT) for precise depth control, and the latest advanced gun deployment system for conveyance of long gun strings under pressure. Innovative solutions implemented throughout the project included the perforation-shock-resistant bottomhole assembly (BHA), two independent emergency disconnects, and tuned software to predict and evaluate shock load and dynamic underbalance. Some of the unique technical solutions were designed specifically for this project: high-pressure and H2S-rated connectors; specialized tool deployment stack; 15,000-psi working pressure 5.12-in. ID H2S-rated rounded scallop guns; shock-resistant electrical disconnect; and high-tensile CT logging head disconnect weak points.
To date, more than 10 well commissioning operations were successfully completed with this innovative method—e-line-enabled CT perforation under high pressure. This perforation technique proved to effectively minimize operational time, associated risks, improper equipment use, and footprint on location. Such approach allowed safe and efficient perforation in a controlled well environment that resulted in accurate depth control and managed detonation shock load and overbalanced conditions, which avoided any well fluid influx or H2S release. The developed solution required seamless integration of innovative techniques and hardware, including e-line enabled CT, the CT logging head, the gun deployment system for pressurized well conditions, wireline tools and specialized perforation equipment. The design was optimized to perforate the well in three or four runs at overbalanced condition (squeeze mode) in a single rig-up job instead of more than 20 wireline runs. Additionally, the use of CT granted flexibility and increased operational safety to perform pumping operations for well displacement and well control, injection of H2S scavenger, and stimulation, as per Operator's plan, without or with only partial rig-down.
This is the first time that the described CT perforation operation using such techniques has been performed in the Caspian region. The experience demonstrates a method to safely and efficiently facilitate perforation jobs under challenging conditions in the future.