Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract Smart Liners rely on the limited-entry principle where a number of small holes act to distribute acid along the un-cemented reservoir section. Over the past two years, this technique has become a key method for matrix-acid stimulation of ADNOC's carbonate reservoirs. The objective of this paper is to summarize the learnings from more than 100 deployments and tie together the key elements of the hole spacing design, the stimulation job execution, and the performance monitoring. A software algorithm generates the hole spacing design to honor a predefined acid flow distribution along the drain length. Quantification of the stimulation efficiency is addressed in several ways. First, the baseline well performance is established with production tests covering several months and in some cases accompanied by a pre-stimulation production logging test (PLT). The stimulation job is then analyzed and compared against a wormhole model to derive the transient injectivity improvement versus acid volume pumped. After the stimulation, the stabilized performance is analyzed in terms of production testing and occasionally a pressure buildup survey and a PLT. Results have so far been very encouraging. Smart Liners have been deployed predominantly in oil producers and water injectors but a few implementations have targeted tight gas reservoirs. A typical steady-state productivity gain is 100-150% above the baseline unstimulated well and the technique consistently outperforms conventional matrix-acid stimulation techniques. The post-stimulation PLT's show that the entire wellbore contributes to flow, even in extended-reach wells. The majority of the efficiency improvement seems to occur with an acid coverage of 0.5 bbl/ft but some wells benefit from higher acid dosages. A wormhole model developed specifically for this completion-stimulation method can reproduce the observations and helps guide designs of future stimula0tion jobs by suggesting modifications to the hole spacing, which will improve the performance improvement using less acid volume.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.21)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
- Asia > Middle East > Turkey > Selmo Field (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Al Shaheen Field > Shuaiba Formation (0.99)
- (9 more...)
Abstract This work presents a well performance analysis technique that identifies formation damage and/ or productivity loss real-time using rates derived from measured well temperatures. It also provides insights into expected damage mechanisms enabling efficient stimulation treatments. The analytical technique recognizes damage patterns at inception. The diagnostics to drive operational decisions are then presented as simple cartesian plots that grant easy access to users of all levels of experience. Data driven temperature-to-rate models provide continuous conversion of flowing well temperatures to production rates that help automate diagnostics for optimum daily surveillance. Case studies from several deepwater wells demonstrate how the technique has been successfully operationalized to eliminate productivity losses, gain early insight into damage mechanisms, and investigate the impact of well interventions. Evaluations and comparisons using pressure transient analysis (PTA), rate transient analysis (RTA) and numerical history matching studies conducted with and without temperature derived rates corroborate the robustness of the method. Temperature derived rates exhibit less than 3 % error when compared to well tests, multi-phase, and ultrasonic flow meters. Shutting in the wells is not required for the analysis, therefore lost production and additional stress cycles on the completion are eliminated. The analysis identifies the maximum drawdown limit, thereby helping the operator optimize well performance real-time. In addition, a data driven approach is outlined for estimating PTA equivalent skin values without shutting-in the wells. Data driven temperature-to-rate models can be developed and maintained with little effort to improve rate allocations, cut back on metering costs, and reduce operational complexities associated with increased number of tests.
- Production and Well Operations > Artificial Lift Systems > Gas lift (0.94)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.89)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (0.87)
- (4 more...)
Abstract Smart Liners rely on the limited-entry principle where a number of small holes act to distribute acid along the un-cemented reservoir section. Over the past two years, this technique has become a key method for matrix-acid stimulation of ADNOC's carbonate reservoirs. The objective of this paper is to summarize the learnings from more than 100 deployments and tie together the key elements of the hole spacing design, the stimulation job execution, and the performance monitoring. A software algorithm generates the hole spacing design to honor a predefined acid flow distribution along the drain length. Quantification of the stimulation efficiency is addressed in several ways. First, the baseline well performance is established with production tests covering several months and in some cases accompanied by a pre-stimulation production logging test (PLT). The stimulation job is then analyzed to derive the transient injectivity improvement versus acid volume pumped. After the stimulation, the stabilized performance is analyzed in terms of production testing and occasionally a pressure buildup survey and a PLT. Results have so far been very encouraging. Smart Liners have been deployed predominantly in oil producers and water injectors but a few implementations have targeted tight gas reservoirs. A typical steady-state productivity gain is 100-150% above the baseline unstimulated well and the technique consistently outperforms conventional matrix-acid stimulation techniques. The post-stimulation PLT's show that the entire wellbore contributes to flow, even in extended-reach wells. The majority of the efficiency improvement seems to occur with an acid coverage of 0.5 bbl/ft but some wells benefit from higher acid dosages. A wormhole model developed specifically for this completion-stimulation method can reproduce the observations and helps guide designs of future stimulation jobs by suggesting modifications to the hole spacing, which will improve the performance improvement using less acid volume.
- Europe (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.21)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
- Asia > Middle East > Turkey > Selmo Field (0.99)
Wells and Facilities Instrumentation and Automation Towards Achieving Field Intelligence
Salim, M. M. (Schlumberger, Abu Dhabi, UAE) | Traboulay, I. (Schlumberger, Houston, USA) | Ahmed, G. S. U. (Schlumberger, Abu Dhabi, UAE) | Ibrahim, E. (ADNOC HQ, Abu Dhabi, UAE) | Al Wehaibi, S. (ADNOC Onshore, Abu Dhabi, UAE) | Al Hammadi, O. (ADNOC Onshore, Abu Dhabi, UAE) | Ballaith, N. (ADNOC Onshore, Abu Dhabi, UAE) | Al Houqani, M. (ADNOC Onshore, Abu Dhabi, UAE)
Abstract A well is a conduit that connects the hydrocarbon deposits in the subsurface to the facilities that transfers and processes it. Understanding the flow of oil or gas through the source rock can only be made possible from the wells itself. Aside from the flow conduits, wells are the only point of reference to understand the field wide behavior. This information is critical to manage the reservoir, ensuring sustainable production throughout the field life. Traditionally, acquiring data from the subsurface to the wellhead relies on intervention, conveying instruments downhole with wireline or coiled tubing. Though effective, this activity incurs costs, logistically challenging and only sporadically available. Surface flow parameters such as rate and pressure are usually measured by analog gauges and Barton chart measurements, which are read manually by personnel to be tabulated later. In most cases, these data can be lost without a proper data management system in place. With the advent of digital instruments, parameters such as pressure, temperature and flowrates; can now be measured automatically and transmitted to a DCS or SCADA system. Some downhole completions are now equipped with instruments that are robust and accurate to take measurements even in extreme conditions of heat and pressure. With data at high availability, engineers are now able to conduct analysis faster, applying data analytics, collaboration and decision making. The main value for Digital Oilfield (DOF) is to save time in data retrieval, analysis and decision making and allow domain engineers to perform higher analytical function and decision making, taking them out from repetitive, manual work through automation. This paper will describe the minimum instrumentations for all well types and major oil and as process facilities for real time data acquisition required to run DOF workflows. This covers subsurface wellbore to production manifold to custody transfer meters.
- Well Completion (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
- (5 more...)
Long Term Development Implications of Parent-Child Interactions in Unconventional Reservoirs
Srinivasan, Karthik (XTO Energy Inc) | Faulk, Andrew Bryce (XTO Energy Inc) | Sanders, Karen Elizabeth (XTO Energy Inc) | Guice, Kyle Brandon (XTO Energy Inc) | Ramirez, Melissa Y (XTO Energy Inc) | Mohan, Lavanya (XTO Energy Inc) | Rajput, Nandini (XTO Energy Inc) | Weisman, Daniel (XTO Energy Inc) | Malpani, Rajgopal (XTO Energy Inc)
Abstract This paper examines the impact of parent depletion on well performance of child wells in a stacked pay unconventional basin with horizontal wells landed in multiple benches. Both intra-bench and inter-bench parent-child were considered, and examples described. This paper also addresses future development implications that result from best-bench-first development in stacked unconventional plays as a function of degradation in child well EURs. This work focuses on both horizontal/vertical interference where presence of pre-existing fracs and depletion in parent wells impact fracture height growth/length and resulting productive frac size in child wells. Two case studies were selected to demonstrate intra-bench and inter-bench parent-child degradations. In the first case study focused on intra-bench parent/child, two adjacent development sections were evaluated, each having been developed as phased developments (multiple landing targets) and with a 9-month lag in first production between the sections. In the second case study focused on inter-bench parent/child, two nearby sections were considered in which different phased development strategies were employed across three distinct landing targets. In both case studies, significant child well degradation was observed in both bottom hole pressures and well production data; observations of impacts to parent wells were also noted. These findings are further supported by modeling efforts. Combined, these case studies indicate that both inter-bench and intra-bench parent-child are significant concerns in stacked unconventional plays, such as those found in the Permian Basin. Our attempts to fully negate the impact of parent-child through later development choices, or to develop child wells without waste, have proven unsuccessful. Complete mitigation of parent-child impacts requires both co-development of potentially connected landing targets (inter-bench) and mow-down development of adjacent development sections (intra-bench).
- North America > United States > Texas (0.25)
- North America > United States > New Mexico (0.25)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (22 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- (3 more...)
Unconventionally Hydraulic Fractured Wells to Develop a Tight Sour Oil Reservoir
Mandhr, Al Kalbani (Petroleum Development Oman) | Yong, Ouyang (Petroleum Development Oman) | Ameera, Al Harrasi (Petroleum Development Oman) | Saif, Al Jarradi (Petroleum Development Oman) | Dmitrii, Smirnov (Petroleum Development Oman) | Kifah, Al Tobi (Petroleum Development Oman) | Aida, Al Khusaibai (Petroleum Development Oman) | Tom, Lefeber (Petroleum Development Oman) | Al Ghaliya, Al Shabibi (Petroleum Development Oman) | Jose, Viota (Petroleum Development Oman) | Zuwaida, Al Saadi (Petroleum Development Oman)
Abstract Summary A field in the southern Sultanate of Oman producing from a tight salicylate reservoir is being studied to evaluate its development potential with unconventional hydraulically fractured vertical wells after initial results from two proof-of-concept wells were positive. The reservoir is more than 3,000 m deep, trapped in salt and over-pressured. It contains sour oil with H2S/CO2 contents of 1 and 2 mol%, respectively, and highly saline formation brine. Although the reservoir has good porosity, the formation is tight with micro-Darcy permeability. Of the eight producers present, two producers have been fracked unconventionally hydraulically with 6 and 15 stages, respectively. The study aims to develop such a field with unconventionally hydraulically fracked producers to mature commercial volumes and meet the value drivers of the project. Development of the field is intended to be phased, starting with the crestal area to reduce risk, and progressing to the flanks over time. The project went through several phases and milestones to explore project decisions and select the optimal options to meet the project's value drivers. The team was tasked with economically optimizing the number of wells, well placement and frac design, well material and completion, and developing a solution for halite scale precipitation. Frac parameters were first matched in Ghofer frac model to match frac job parameters for the two existing unconventionally fracked wells. Dynamic simulation models with frac models were used to match well test and Production-Log (PLT) data. These models were then used to generate production forecasts to support project decision-making and maximize value while ensuring project competitiveness within the company's project portfolio. To address halite scaling potential during frac fluid recovery, water samples were collected and analyzed for compatibility and scaling potential and to optimize a scaling mitigation strategy. The two unconventionally fracked wells produced longer fractures than the conventional wells and have shown to deliver greater economic oil rates. Sonic noise log and well test results demonstrate that guar-based gel produces thicker and shorter cracks. High-viscosity friction reducer (HVFR) produces thinner but much longer fractures. Unconventional fracs increase reservoir coverage by three times compared to conventionally fracked wells, resulting in a five-fold increase in oil recovery at higher pipe-head pressures. From these findings, the decision is made for unconventional fracs, cleaner HVFR frac fluid, and fracture conductivity damage of about 15-25%. The optimal unconventional frac design and well spacing were considered dependent and evaluated in combination. Key well design, completion, and material decisions were made considering production conditions to safely produce commercial oil. To reduce the outcome uncertainty and implementation risk while developing the field, multiple scenario trees were constructed, which were used to decide on the phased manner for field development. The study shows that well spacing and optimal number of wells should be studied with frac design. All decisions related to subsurface, frac technology and well design should be made in an integrated manner, considering the circumstances of the project to make optimal decisions.
- Asia > Middle East > Oman (0.34)
- Europe > Norway > Norwegian Sea (0.25)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.50)
- Geology > Mineral > Halide > Halite (0.44)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (3 more...)
Downhole Water Sink at High Mobility Ratio: The Tambaredjo Field Pilot Test
Niz-Velasquez, E. (Dunia Technology Solutions, Paramaribo, Suriname) | Nagesar, H. S. (Staatsolie Maatschappij N.V., Paramaribo, Suriname) | Bhajan, R. V. (Staatsolie Maatschappij N.V., Paramaribo, Suriname) | Nandlal, B. (Staatsolie Maatschappij N.V., Paramaribo, Suriname)
Abstract This study discusses the development and results of the Downhole Water Sink (DWS) pilot test in two wells of the Tambaredjo Field (Suriname). It includes the mechanical completion, design and execution of operating strategy, well performance and forecast, and reservoir simulation employing an oil-in-water emulsion formulation. The DWS process, well and reservoir information and properties are introduced. The problem of heavy oil production in oil-water contact (OWC) areas is explained. The results in terms of production data and its analysis, and issues encountered, are presented. A reservoir simulation model capable to handle transport of oil components in water phase is described and used to history-match the production performance. Then, conclusions are drawn from the information presented. Although the water sink is expected to work under stable displacement conditions, the results of the pilot test show that DWS could successfully reduce water coning at the prevalent unstable mobility ratio. It also promoted inverted coning of oil from the transition zone to the water leg completion. This was confirmed by direct measurements of oil content in the fluid produced from the water leg completion. The physical mechanism that allows such phenomenon is hypothesized to be the flow of oil droplets of size smaller than that of the typical pore throat. Such mechanism was numerically modeled and found to be consistent with the pressure and rate measurements at both wells. Early measurement and completion issues in the first well were overcome later on and in the second well. This paper presents the first results for DWS in a heavy oil reservoir with highly adverse mobility ratio. The results will serve as a guidance for implementation of DWS in heavy oil reservoirs overlying an oil-water contact.
- North America > United States (1.00)
- South America > Suriname > North Atlantic Ocean (0.61)
- South America > Guyana > North Atlantic Ocean (0.61)
- Europe > United Kingdom > North Sea > Central North Sea (0.40)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.97)
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.97)
Advancement of Open Hole Gravel Pack and Zonal Isolation with Selective Intelligent Completion in Deepwater Malaysia
Samuel, Elvy (PTTEP Sarawak Oil LTD) | Nopsiri, Noppanan (PTTEP Sarawak Oil LTD) | Chan Fong, Lee (PTTEP Sarawak Oil LTD) | Kalalo, Alxner (Pertamina Malaysia EP) | Moses, Nicholas (Schlumberger Malaysia) | Jayadi, Agus (Schlumberger Malaysia) | Yi, Ding (Schlumberger Malaysia) | Nordin, Amirul (Schlumberger Malaysia) | Teoh, Melissa (Schlumberger Malaysia)
Abstract As fields mature, the drilling and completion design and execution for infill development becomes challenging. In a deepwater environment, one of the strategies to address this challenge is to optimize subsea facilities by targeting several reservoir packages in a single wellbore. However, this technique comes with technical challenges because penetrating different zones requires active reservoir management, an allowance for zonal isolation, and an adequate response to potential crossflow. A smart completion architecture should overcome these constraints and reduce overall capital expenditure while maximizing production. Furthermore, for wells requiring sand control, the completion solution must ensure a reliable and proven approach that minimizes the potential completion failures introduced by unsuccessful sand retention. This paper presents the completion strategy implemented in an intelligent well completed in the Malaysian deepwater Block K, during the field development of Siakap North Petai (SNP) Phase 2 and executed in Q1 2022.
- North America > United States (1.00)
- Asia > Malaysia > Sabah > South China Sea (0.34)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > P 1575 > Block 9/2c > Kraken Field > Heimdal Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > P 1575 > Block 9/2b > Kraken Field > Heimdal Formation (0.99)
- Asia > Malaysia > Sabah > South China Sea > Sabah Basin > Block K > Siakap North and Petai Fields (0.99)
- (5 more...)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drillstring Design (1.00)
- Well Drilling > Drilling Operations (1.00)
- (12 more...)
Abstract Sand production prediction is essential from the early stages of field development planning for well completion design and later for production management. Unconsolidated and weakly consolidated sandstones are prone to fail at low flowing bottom hole pressures during hydrocarbon production. To predict the sand-free drawdown, a robust sand prediction model that integrates near-wellbore and in-situ stresses, rock mechanical properties, well trajectory, reservoir pressure, production and depletion trends is required. Sanding prediction models should be calibrated with field data such as production and well tests observation. In the absence of field data, numerical techniques can provide a reliable estimate on potential onset and severity of sanding at various reservoir pressures. In this study, analytical and finite-element numerical models are independently used to predict the onset of sanding and volume of produced sand from high rate has wells with weakly consolidated sandstone reservoirs in onshore, Western Australia. The analytical method uses a poro-elastic model and core-calibrated log-derived rock strength profiles with an empirical effective rock strength factor (ESF). In the study, the ESF was calibrated against documented field sanding observation from a well test extended flow period at the initial reservoir pressure under a low drawdown pressure. The numerical method uses a poro-elasto-plastic model defined from triaxial core tests. The rock failure criterion in the numerical method is based on a critical strain limit (CSL) corresponding to the failure of the inner wall of thick-walled cylinder core tests that can also satisfy the existing wells sanding observations. To verify the onset and severity of sanding predicted by the analytical model, numerical simulations for an identical sandstone interval are developed to investigate the corresponding CSL. This combined analytical and numerical modelling calibrated with field data provided high confidence in the sanding evaluation and their application for future well completion and sand management decisions. The analytical model was finally used for sanding assessment over field life pressure condition because of its processing simplicity, speed and flexibility in assessing various pressure and rock strength scenarios with sensitivity analysis over the whole production interval in compared with the numerical method which is more suitable for single-depth, single pressure condition and well and perforation trajectory modelling.
- North America (0.68)
- Oceania > Australia > Western Australia (0.48)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.98)
- Well Completion > Sand Control (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)
Applying Survival Analysis to Sand Failure Control Risk
Yang, Huihui (Shell International Exploration & Production, Inc.) | Tallin, Andrew (Shell International Exploration & Production, Inc.) | Lu, Ligang (Shell International Exploration & Production, Inc.) | Xiao, Xiaohui (Shell International Exploration & Production, Inc.) | Valteau, Lisa (Shell International Exploration & Production, Inc.) | Wei, Jia (Shell International Exploration & Production, Inc.) | Chen, Jay (Shell International Exploration & Production, Inc.)
Abstract Sand production affects safety, reliability, equipment integrity and economics. To help production engineers understand and quantify sand control risks, we built sand control survival application. This application displays how survival is impacted by operating and well parameters as a function of cumulative production, which can help to save oil and gas industry hundreds of millions of dollars per year. Our application uses a dataset that tracks survival status and corresponding cumulative productions for more than 300 completions in GOM. Field data covering water cut, flowing pressure decline, and sand control survival was compiled and analyzed to determine the impact these both single and multiple cofactors on survival, which save time and cost while improving the overall quality of information.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Well Drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Well Completion > Sand Control > Screen selection (0.68)