|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer. This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data. The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
Summary To determine which salt-based cement system (potassium chloride or sodium chloride) was suitable for cementing across halite and anhydrite salt sections in West Africa, eight slurry recipes were tested to assess how formation salt contamination would affect slurry properties. The formation salt used for testing was sampled from a deepwater, presalt well in Angola. The recommendations developed from the laboratory study were implemented in 10 projects across West Africa over 5 years with 100% operational and well integrity success. A candidate deepwater well was selected in which the surface and intermediate strings penetrated salt formations. Four slurry designs (a lead and tail slurry used on each casing string) were programmed. Each slurry was designed and tested as two distinct systems using potassium chloride and sodium chloride salt, respectively, yielding a total of eight slurry designs. Using the methodology and data presented by Martins et al. (2002), the mass of dissolved formation salt that each slurry may receive during placement was estimated and duly incorporated into each slurry design. Subsequently, the salt-contaminated slurries were tested and compared with the properties of the initial uncontaminated slurries. On the basis of these results, conclusions were then made on which salt slurry system (potassium chloride or sodium chloride) exhibited better liquid and set properties after contamination with formation salt. Subsequently, this knowledge was applied to 10 projects across three countries in West Africa. This study showed that when the contact time of liquid cement slurry to salt formation was low—typically when the salt-formation interval across which the cement slurry flowed was less than 100 m thick—the level of formation salt dissolution entering the slurry during placement was limited. In this case, a potassium chloride salt-based slurry delivered improved liquid and set properties as compared with a sodium chloride salt-based slurry. In the field, this knowledge was applied in all oilfield projects cemented by an oilfield service company between 2015 and 2020. This included deepwater, shallow offshore, and onshore wells. All related salt-zone cement jobs, including sidetrack plugs, placed across the salt formations were successful on the first attempt. In an absence of industry consensus around salt-formation cement slurry design, this paper validates a guideline for West Africa, based on results from laboratory testing and 5 years of field application. In contrast to current literature that recommends only sodium chloride salt-based slurry designs across halite or anhydrite salt intervals, this work demonstrates that potassium chloride salt-based slurry systems can effectively be used to achieve well integrity where a halite or anhydrite salt interval is less than 100 m (328.1 ft) thick.
Brillaud, Loïc (Helmerich & Payne) | Couliou, Florent Emile (Helmerich & Payne) | Mathisen, Kim (NOV Completion) | Koloy, Tom (NOV Completion) | Lacaze, Chloé Lucie (Total) | Balou, Efficience Bassy (Total) | Bledou, Manfred Konan (Total) | Delabrousse-Mayoux, Géraud (Total) | Drevillon, Pierre-Marie (Total)
Abstract This paper describes the innovative engineering workflow which has been used to ensure the safe deployment of deep production liners on long step-out wells of a deep offshore development field. It highlights the importance of accurate Torque & Drag modelling during planning and operations and provides details on how the use of downhole data assisted in understanding downhole conditions on the first wells, which allowed to optimize the running and setting procedure for the next wells of the field. For this methodology, a unique Torque & Drag stiff-string model was used to simulate the evolution of side-forces, tension, stretch, torque and twist along the string at every stage of the deployment and setting of the liner. Simulations were performed both during planning phase and operations. Once the well completed, downhole memory data from a logging tool was compared with simulations, which allowed to calibrate the model, better understand downhole conditions, and provide recommendations for the next runs. Using this methodology, the operator succeeded in deploying the liner to total depth, setting the hanger and packer successfully on all the wells of the field. These operations were performed with only 40 minutes of non-productive time throughout the campaign. The paper shows how correlating downhole data with Torque & Drag simulations highlighted areas of improvement and allowed to optimize the running and setting procedure of the liner. It also led the operator to gain confidence in the feasibility of such critical operations even on the more challenging wells. Detailed engineering and collaboration were key to this success. Such methodology can be applied on every well where weight transfer is a potential issue. As the industry is heading towards digitalization and automation, this case study is a prime example which demonstrates the added value of combining advanced physics-based simulations with time based downhole data.
Bledou, Manfred (Total) | Caillon, Didier (Total) | Groschaus, Benjamin (Total) | Viger, Guillaume (Total) | Singh, Harpal (Total) | Bagal, Joseph (Welltec) | Hallaire, Maximilien (Welltec) | Onadeko, Olugbenga (Welltec) | Hazel, Paul (Welltec) | Vasquez, Ricardo (Welltec) | Wallach, Mathieu (Welltec) | Fürstnow, Mette (Welltec)
Abstract This paper will discuss a game-changing and innovative technology that enabled cementless annular isolation (liner to borehole) across the reservoir, removing the risk of previous experienced cost and time overrun from complex cement operations and securing the full economical return on the wells. The technology has been deployed in four Moho North Albian wells, drilled through a complex reservoir with highly laminated lithology requiring efficient zonal isolation for both acid treatment and water shut off. During the earlier field development, many cementing challenges were encountered that increased risk and cost and the ability to deliver effective isolation across the reservoir. Poor isolation leads to poor matrix acid stimulation, higher skin and a higher risk of water production. To address this the operator sponsored an industry challenge to achieve reservoir isolation with cost and risk reduction and to deliver overall efficiency gains. Through dialogue between the Operator and a leading service provider in Open Hole Zonal Isolation, a solution was identified that would effectively replace the cement across the reservoir with a metal expandable annular sealing system. Time for delivery was a key driver to meet the drilling schedule and materialize the cost and risk reductions on the remaining wells. A scope of work was completed that included extensive qualification, manufacture and field deployment. The solution has proven to deliver benefits that address several fundamental aspects which were associated with the cemented liners: Substantial reduction in risk and cost associated with drilling the extended rat hole (shoe track) into the highly pressurized water zone (+/- 100mMD) Removed the risk and cost for the additional run to under ream the 6 ½″ hole to 7 ¼″ (low-ROP) Provided more certainty for zonal isolation whilst delivering effective acid stimulation and maintaining the low skin values. The technology has many different applications within wells where conventional cement is challenged beyond its capabilities and inherently not fit for purpose, due to factors such as well trajectory, hole geometry, reservoir uncertainty, downhole environment (pressure, Temp, ECD) etc. Within these environments, the technology developed for Moho North adds a proven solution to the Operators toolbox, a technology that is already finding alternate applications and planned deployments.
Al Kalbani, Mandhr (Heriot–Watt University) | Al Shabibi, Hatem (Heriot–Watt University) | Ishkov, Oleg (Heriot–Watt University) | Silva, Duarte (Heriot–Watt University) | Mackay, Eric (Heriot–Watt University) | Baraka-Lokmane, Salima (Total) | Pedenaud, Pierre (Total)
Summary Injection of low-sulfate seawater (LSSW) instead of untreated full-sulfate seawater (FSSW) is widely used to mitigate barium sulfate scaling risk at the production wells. LSSW injection may no longer be required when the barium concentrations in the produced water drop below a certain threshold. Such a trigger value could be estimated from the barium sulfate precipitation tendency. Relaxation of requirements for the sulfate reduction plant (SRP) can significantly reduce operational costs. This study investigates the impact of several parameters on the timing and degree of relaxation of the output sulfate concentration by the SRP. Finally, the optimal switching strategy is proposed for a field case. The strategy for switching from LSSW to FSSW (e.g., time and method; direct or gradual increase in the sulfate concentration) was initially investigated using generic 2D areal and vertical models. The sensitivity study included the impact of reservoir heterogeneity and the initial barium and sulfate ion concentrations. Findings were later applied on a full-field reservoir simulation model followed by a mineral scale prediction software to investigate the specific switching strategy for a field that has multiple wells and significantly more complex heterogeneity. The results show that barium concentrations in the formation brine affect the choice of switching time more than the output sulfate concentration produced by the SRP. The degree of heterogeneity around the producers also has a significant impact on the switching time. Another parameter is the contrast in the permeability between layers; higher contrast allows a longer period of coproduction of the scaling ions and thus delays the switching time. In the field case, switching to FSSW at early times allows higher consumption of barium ions because of its in-situ precipitation. Barium is no longer a limiting ion, and so a higher degree of deep reservoir precipitation reduces the requirement for prolonged LSSW injection. Another strategy is a gradual relaxation of LSSW output, which allows even earlier buildup of the injected sulfate concentration compared with the direct FSSW switch. The study investigates the reservoir parameters that affect sulfate relaxation of LSSW injection for a field. After the proposed workflow, the optimal relaxation strategy can be designed for other field cases.
Hydrogen sulphide (H2S) is naturally occurring in many oil and gas production streams. H2S scavengers are used as additives to reduce the concentration of H2S gas in order to meet export gas/crude specification or for mechanical integrity requirement. Most Total installations today use conventional chemicals such as monomethyl amine (MMA) and monoethanolamine (MEA) triazines for H2S removal. According to Total affiliates, deposit formations have been observed when triazine based scavengers are used. In this paper alternative chemistries for H2S scavenging are assessed. Six H2S scavengers have been evaluated, these are: Methylene bis-Oxazolidine (MBO), Ehylenedioxy Dimethanol (EDDM), 2-Ethyl Zinc Salt, Glyoxal, Hemiacetal and MEA Triazine. For the evaluation of H2S scavenger's efficiency, an experimental method has been developed.
For the selection of H2S scavengers, the following tests have been carried out: (i) evaluation of H2S scavenger efficiency in the oil and gas phase and (ii) production chemical compatibility test. The three-best performing H2S scavengers have been analysed for (i) the impact of H2S scavenger on foaming; (ii) impact of H2S scavenger on emulsion; (iii) compatibility between H2S scavenger and production water; (iv) effect of H2S on the scale inhibitor efficiency; (v) effect of H2S on the corrosion inhibitor efficiency.
Laboratory tests have shown that the three best H2S scavengers, based on the performance test, are Zinc 2-ethylhexanoate, Methylene bis-Oxazolidine (MBO) and Triazine. Methylene bis-Ozaxolidine tested on North Sea site in the multiphase and gas phase has shown preliminary good results. No impact on emulsion, foaming and corrosion were observed from the three-best H2S scavengers selected. Test performed on site with zinc-based product showed very good performance on H2S removal but impacted produced water quality. The zinc-based product formed deposits when mixed with production water therefore this H2S scavenger should not be used for scavenging H2S in the water phase. Though Triazine and MBO based scavengers increase water pH, potential scaling issues can be mitigated by scale inhibitor, however dithiazine deposits formed with the use of triazine based scavengers limits its use for H2S scavenging in oil gas installations.
An experimental method has been developed for the evaluation of H2S scavengers. Alternative scavenger chemistries have been identified. These chemistries reduce the risk of deposit formation in the H2S removal process during oil and gas production.
Many oil & gas operators are now seeing unmanned facilities as the next frontier for safer operations and further cost reductions. However, these benefits only appear once the time between site visits is extended as much as possible. In its Next-Generation Facilities concept, Total is pushing the limits by targeting planned interventions only once a year.
Tremendous challenges must be tackled to make this concept a reality, from initial lean and robust facility design to management of operations. Subsea installations remain a source of inspiration on many levels, particularly for the handling of inaccessible installations using Remote Operated Vehicles.
As a result, Total has been very active in the field of autonomous ground robotics for many years with its ARGOS project. Many other oil & gas operators or robot manufacturers are also following similar paths. Consequently, more and more videos showing a robot on site, tele-operated or not, in the direct sight of a technician in charge of its control have been published. Improving robot capabilities, testing and learning how to handle these new tools is important and a very encouraging signal for the industry, but the integration and cost scaling effect are still to be demonstrated.
A step change in the experimentation has to materialize, since one robot alone on a site will not be able to achieve much. Moreover, the reproduction of the scheme ‘one robot/one technician’ is not optimal when numerous robots are involved.
Therefore, the addition of a new component in the field architecture in charge of bridging robot site activities and the off-site Control Room is seen as essential to rise to the next level and meet the requirement of the new operating philosophy: continuous operations with multiple robots working simultaneously on an unattended site. Total calls this new function the "Operation Room". In Total's concept, the Operation Room is located next to the existing Control Room which would also become remote. From the Operation Room, robot panel operators, very much like air traffic controllers, will remotely supervise and coordinate the robots that will autonomously perform the very activities that the field operators once used to do on conventional facilities, from routine operation and maintenance tasks to emergency response.
This article will give an overview and some examples of how Total has matured the design of its Operation Room concept, including a description of the key elements that have to be addressed to manage a fleet of autonomous robots in an efficient and safe manner from a remote location.
To determine which salt-based cement system [potassium chloride (KCl) or sodium chloride (NaCl)] was suitable for cementing across halite and anhydrite salt sections in West Africa, eight slurry recipes were tested to assess how formation salt contamination would affect slurry properties. The formation salt used for testing was sampled from a deepwater, presalt well in Angola. The recommendations developed from the laboratory study were implemented in 10 projects across West Africa over 5 years with 100% operational and well integrity success.
A candidate deepwater well was selected in which the surface and intermediate strings penetrated salt formations. A total of four slurry designs (a lead and tail slurry used on each casing string) was programmed. Each slurry was designed and tested as two distinct systems using KCl and NaCl salt respectively, yielding a total of eight slurry designs. Using the methodology and data presented by Martins et al. at the 2002 IADC/SPE Drilling Conference (SPE-74500-MS), the mass of dissolved formation salt that each slurry may receive during placement was estimated and duly incorporated into each slurry design. Subsequently, the salt-contaminated slurries were tested and compared with the properties of the initial uncontaminated slurries. Based on these results, conclusions were then made on which salt slurry system (KCl or NaCl) exhibited better liquid and set properties after contamination with formation salt. Subsequently, this knowledge was applied to 10 projects across three countries in West Africa.
This study showed that when the contact time of liquid cement slurry to salt formation was low—typically when the salt formation interval across which the cement slurry flowed was less than 100 m thick—the level of formation salt dissolution entering the slurry during placement was limited. In this case, a KCl salt-based slurry delivered improved liquid and set properties as compared with a NaCl salt-based slurry. In the field, this knowledge was applied in all oilfield projects cemented by an oilfield service company between 2015 and 2020. This included deepwater, shallow offshore, and onshore wells. All related salt-zone cement jobs, including sidetrack plugs, placed across the salt formations were successful on the first attempt.
In an absence of industry consensus around salt-formation cement slurry design, this paper validates a guideline for West Africa, based on results from laboratory testing and 5 years of field application. In contrast to current literature that recommends only NaCl salt-based slurry designs across halite or anhydrite salt intervals, this work demonstrates that KCl salt-based slurry systems can effectively be used to achieve well integrity where a halite or anhydrite salt interval is less than 100 m [328.1 ft] thick.
Farooq, Umer (ADNOC Onshore) | Meyer, Arnaud (Total) | Al Obeidli, Aisha Khalil (ADNOC Onshore) | Ben Maroof, Muneera (ADNOC Onshore) | Baloch, Shahid Ali (ADNOC Onshore) | Kumar Dey, Swapan (ADNOC Onshore) | Almarzooqi, Maitha Jawhar (ADNOC Onshore)
A brown field producing from an Upper Cretaceous carbonate reservoir has 35 years of production history with challenges of water management and sweep efficiency affecting production plateau duration and ultimate recovery. To mitigate the challenges the reservoir characterization must be updated in order to optimize the field development plan. The reservoir is very heterogeneous with evidence of dual medium behavior which is attributed mainly to fractures. In addition to fractures, the presence of karst features in the reservoir were identified in several cored wells as part of the major field review. As a result, a comprehensive karst characterization study was conducted on the three reservoir units with the objective of describing and understanding the karst development across the field. The ultimate goal was to enhance reservoir understanding and update the conceptual reservoir model.
The study was conducted in three phases. The first phase of the study focused on identifying karst features on cores from 41 wells (~10,000ft of core) which are well distributed across the field. All the intervals with different types of karst features in each well were identified and marked. The second phase was the integration of static and dynamic data. The third phase of the study updated the conceptual reservoir model integrating all the findings. The Karst development in the reservoir corresponded to both early and late diagenetic processes and occurred mainly in reservoir Unit-1 and Unit-3. The early diagenetic process attributed to the formation of epikarst (paleosoil, dolocrete, and hardground) mainly in Unit-1. Epigenetic karst resulted in the development of solution collapse breccias occurring extensively in crestal field position below the top of Unit-3. Late diagenetic process attributed to hydrothermal karst formation (dissolution vuggs and presence of saddle dolomite) mainly identified in Unit-3 and correspond to hydrothermal fluid circulation via deep-rooted faults. Integration of karst features from cores, image logs and seismic attributes with dynamic data depicted clearly the dynamic influence of the karst development in the reservoir (i.e. high Kh values from well tests, production from collapse brecciated intervals-PLT, and early water breakthrough). These effects are more profound in the southern crest of the field. Finally, a conceptual reservoir model was developed and was crucial in integrating both static and dynamic data. This study was unique as karst influence on reservoirs are not common and not very well understood in the region. The integrated workflow to characterize karst development using both static and dynamic data have been of profound importance in terms of building a good understanding of the reservoir for future well placement and completion. The integrated approach used in generating the karst conceptual model, adequately will guide the update of the reservoir model.
Grifantini, Simona (ADNOC Offshore) | Saqib, Talha (ADNOC Offshore) | Sabri, Abdel Mouez M. (ADNOC Offshore) | Keshtta, Osama M. (ADNOC Offshore) | Albadi, Bader S. (ADNOC Offshore) | Beaman, Daniel J. (ADNOC Offshore) | Al-Hassani, Sultan D. (ADNOC Offshore) | Bigno, Yann (ADNOC Offshore) | Draoui, Elyes H. (ADNOC Offshore) | Bansal, Bhagwan D. (Total)
The giant heterogeneous carbonate field presented here consists of multi-stacked reservoirs and is located in the Arabian Gulf approximately 135 km north-west of Abu Dhabi. The reservoir named "T" measures 9 km by 11.5 km, with large accumulation of 35 °API oil with initial gas oil ratio of about 400 scf/STB. The current reservoir pressure is around 2,700 psi; many of wells are unable to flow naturally against the high sealine pressure, due to low productivity and relatively low GOR. To produce these wells, "artificial lift" or lower sealine pressure are required.
A collaborative team of Reservoir Engineers, Petroleum Engineers and Geoscientists was assigned to find a sustainable and cost-effective solution to produce reservoir "T" in order to evaluate its potential. The team conducted a detailed and comprehensive study of the field starting from reservoir "T" and then expanded to the other reservoirs. As a result, the proposal of an "Auto Gas Lift" (AGL) pilot was formulated to use gas from the reservoir "C" (underlying reservoir T) to artificially lift the oil produced from reservoir T.
AGL is a cost-effective artificial lift system, directly replacing for conventional gas-lift equipment, gas compression facilities, gas transport pipelines and ancillary equipment. This technique has been identified as the most suitable for such mature offshore field, where existing platforms have limited spare load and space capacity and could not accommodate gas-lift compression facilities or ESP topside equipment. The first pilot completion has been designed. It consists of a perforated downhole high GOR zone from which gas is bled into the tubing at a rate controlled by a downhole gas lift valve. The gas produced from high GOR reservoir C will allow reservoir T to flow by reducing the hydrostatic head of the fluid column in the well.
Artificial lift has not been implemented yet in the field. However, several artificial lift techniques, such as Electrical Submersible Pumps or conventional gas lift, are foreseen in long term development plans. "AGL" technique, if successful, could represent a cost-effective solution for further appraisal of this reservoir, without waiting for the implementation of large-scale artificial lift techniques.