Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Unlocking the Potential of Acid Stimulation in Volcanic Rocks: A Successful Case with Integrated Analysis in Minami-Nagaoka Gas Field, Japan
Yoshida, Nozomu (INPEX Corporation (Corresponding author)) | Shimoda, Keisuke (INPEX Corporation) | Yamamura, Keisuke (INPEX Corporation) | Fuse, Kei (INPEX Corporation) | Kaminoyama, Haruki (INPEX Corporation) | Ishigami, Yuki (INPEX Corporation) | Mhiri, Adnene (Schlumberger) | Niu, Li (Schlumberger) | Ramondenc, Pierre (Schlumberger) | Luo, Yin (Schlumberger) | Liu, Wei Qiao (Schlumberger)
Summary Acid stimulation of volcanic formations is rarely documented in the literature. A recent study however suggested its potential effectiveness through a comprehensive laboratory/modeling analysis and documented substantial permeability enhancement by dissolution of carbonate-cemented fractures in the near-wellbore area to create wormhole-like high-permeability channels. The study also presented a brief description of successful field execution, although operational details and analysis of results were not presented. This work presents in detail the field case of a multistage acidizing treatment in the Minami-Nagaoka gas field, a volcanic reservoir, and demonstrates the effectiveness of acid stimulation with 10% formic acid for productivity enhancement. The selection of a target well relies on the abundance of cemented fractures along a well. The operational design considers multiple field/well characteristics, such as low permeability; long, perforated intervals; and high-temperature conditions. Effectiveness of acid stimulation is evaluated comprehensively and justified by the integration of real-time stimulation diagnostics using distributed temperature sensing (DTS), real-time surveillance of bottomhole key parameters obtained thanks to coiled-tubing (CT) fiber-optic downhole telemetry, pre-/post-acidizing pressure buildup (PBU) tests, and production logging tool (PLT) surveys. A multistage acidizing operation was executed, after completion of a step-rate test during which a pre-acidizing DTS survey was acquired. Eight stages of 10% formic acid injection and seven stages of degradable particulate diverter placement were pumped, followed by brine displacement and a post-acidizing DTS acquisition. In all the stages, acid injection decreased the bottomhole pressure while the use of diverter increased it (by hundreds of psi), thus indicating success in acid stimulation and diversion, respectively. The stimulation almost doubled the gas flow rate just after the operation, and 10 months after the operation, the gas rate is still 1.5 times higher than before intervening. Pre-/post-acidizing PBU tests suggested a substantial reduction of the skin from 1.50 to −1.91. DTS surveying identified one major and three minor fluid-intake intervals through stimulation/diversion, and integrated analysis with PLTs revealed that the substantial improvement in gas rate was primarily coming from a narrow zone located within the major intake interval, where resistive fractures are abundant. The current case demonstrates the effectiveness of 10% formic acid for the stimulation of rocks with carbonate-cemented fractures, which was also proposed by the former study. It also shows that there is still room for further optimization in the operational design. This paper provides insights on acid stimulation in volcanic rocks and highlights its effectiveness through the analysis of a series of data sets. Readers may obtain knowledge on acidizing design, the evaluation of its effectiveness, and the interpretation of results, with lessons learned through job execution. The study will also serve as a reference to evaluate the potential of acid stimulation for the development of other volcanic reservoirs.
- North America > United States > Texas (1.00)
- Asia > Japan > Chūbu > Niigata Prefecture (0.61)
- Geology > Geological Subdiscipline > Volcanology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.46)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Unlocking the Potential of Acid Stimulation in Volcanic Rocks: A Successful Case with Integrated Analysis in Minami-Nagaoka Gas Field, Japan
Yoshida, Nozomu (INPEX Corporation (Corresponding author)) | Shimoda, Keisuke (INPEX Corporation) | Yamamura, Keisuke (INPEX Corporation) | Fuse, Kei (INPEX Corporation) | Kaminoyama, Haruki (INPEX Corporation) | Ishigami, Yuki (INPEX Corporation) | Mhiri, Adnene (Schlumberger) | Niu, Li (Schlumberger) | Ramondenc, Pierre (Schlumberger) | Luo, Yin (Schlumberger) | Liu, Wei Qiao (Schlumberger)
Summary Acid stimulation of volcanic formations is rarely documented in the literature. A recent study however suggested its potential effectiveness through a comprehensive laboratory/modeling analysis and documented substantial permeability enhancement by dissolution of carbonate-cemented fractures in the near-wellbore area to create wormhole-like high-permeability channels. The study also presented a brief description of successful field execution, although operational details and analysis of results were not presented. This work presents in detail the field case of a multistage acidizing treatment in the Minami-Nagaoka gas field, a volcanic reservoir, and demonstrates the effectiveness of acid stimulation with 10% formic acid for productivity enhancement. The selection of a target well relies on the abundance of cemented fractures along a well. The operational design considers multiple field/well characteristics, such as low permeability; long, perforated intervals; and high-temperature conditions. Effectiveness of acid stimulation is evaluated comprehensively and justified by the integration of real-time stimulation diagnostics using distributed temperature sensing (DTS), real-time surveillance of bottomhole key parameters obtained thanks to coiled-tubing (CT) fiber-optic downhole telemetry, pre-/post-acidizing pressure buildup (PBU) tests, and production logging tool (PLT) surveys. A multistage acidizing operation was executed, after completion of a step-rate test during which a pre-acidizing DTS survey was acquired. Eight stages of 10% formic acid injection and seven stages of degradable particulate diverter placement were pumped, followed by brine displacement and a post-acidizing DTS acquisition. In all the stages, acid injection decreased the bottomhole pressure while the use of diverter increased it (by hundreds of psi), thus indicating success in acid stimulation and diversion, respectively. The stimulation almost doubled the gas flow rate just after the operation, and 10 months after the operation, the gas rate is still 1.5 times higher than before intervening. Pre-/post-acidizing PBU tests suggested a substantial reduction of the skin from 1.50 to −1.91. DTS surveying identified one major and three minor fluid-intake intervals through stimulation/diversion, and integrated analysis with PLTs revealed that the substantial improvement in gas rate was primarily coming from a narrow zone located within the major intake interval, where resistive fractures are abundant. The current case demonstrates the effectiveness of 10% formic acid for the stimulation of rocks with carbonate-cemented fractures, which was also proposed by the former study. It also shows that there is still room for further optimization in the operational design. This paper provides insights on acid stimulation in volcanic rocks and highlights its effectiveness through the analysis of a series of data sets. Readers may obtain knowledge on acidizing design, the evaluation of its effectiveness, and the interpretation of results, with lessons learned through job execution. The study will also serve as a reference to evaluate the potential of acid stimulation for the development of other volcanic reservoirs.
- North America > United States > Texas (1.00)
- Asia > Japan > Chūbu > Niigata Prefecture (0.61)
- Geology > Geological Subdiscipline > Volcanology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.46)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Pushing the Limits of Damage Identification Through the Combined Use of Coiled Tubing, Distributed Sensing, and Advanced Simulations: A Success Story from Japan
Yoshida, Nozomu (INPEX Corporation) | Teshima, Satoshi (INPEX Corporation) | Yamada, Ryo (INPEX Corporation) | Aybar, Umut (Schlumberger) | Ramondenc, Pierre (Schlumberger)
Summary The success of water‐conformance operations often depends on clear identification of the water‐production mechanism. Such an assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed‐temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water‐bearing zones in an onshore well in Japan. The subject well experienced unexpected contamination of oil‐based mud (OBM) and completion brine, which generated tight emulsions in the wellbore during the completion phase. Despite a thorough cleanout and perforations, severe damage was observed and mostly water was produced. With the presence of persistent damage in the wellbore preventing any logging‐tool use, DTS was selected as main diagnostic method, with the fiber optics being deployed with CT to ensure full coverage of the interval. Acquired temperature surveys were processed and matched with simulated profiles, which tested various scenarios of damage. Ultimately, results were used to drive the design of remedial actions. The following operational sequence was implemented: temperature‐baseline measurements (6 hours), brine bullheading through the CT/tubing annulus at 0.2 bbl/min (22 hours), and shut‐in (6 hours) for warmback. The long injection stage was required to ensure that enough fluid was being injected across the entire interval while keeping the downhole pressure at less than the fracturing pressure. Real‐time DTS data during pumping and warmback indicated the presence of a main intake zone in the middle of the interval. Below that section, only marginal temperature changes were observed, which might be a direct consequence of the low‐injection‐rate limitation. Post‐job processing using numerical temperature simulation was performed to complement that analysis and quantify intake along the well. Temperature inversion against the DTS response was conducted independently using two different simulators, both of which yielded similar profiles, confirming the soundness of this approach. The results supported the presence of a larger intake in the middle interval and also showed that the bottom zone most likely took some fluid. Complementary information eventually pointed to the larger‐intake interval being the primary water‐bearing zone. This analysis led to the selection of the remedial actions to be performed in damaged oil zones. This study demonstrates how integrated use of data from design to job execution to interpretation can change the perception of a well and how DTS can be a viable alternative to damage and water‐production diagnostics in some extreme conditions when production‐logging tools (PLTs) cannot be used. Results of the DTS quantitative analysis provided local damage profiles along the well, which were critical to the subsequent planning of remedial activities.
- North America > United States > Texas (1.00)
- Asia > Middle East (1.00)
- Asia > Japan (1.00)
- Research Report > Experimental Study (1.00)
- Research Report > New Finding (0.68)
Unlocking Operational Efficiencies for Milling Plugs in Large Monobore Completions Using Coiled Tubing with Real-Time Downhole Measurements - A Case Study from Offshore Middle East
Hässig Fonseca, Santiago (Schlumberger) | Molero, Nestor (Schlumberger) | Ramondenc, Pierre (Schlumberger) | Tapia, William (Schlumberger)
Abstract Coiled tubing (CT) milling of downhole plugs in large monobore completions is considered one of the most challenging CT workover operations, especially when conducted in offshore environments where intervention workflows are driven by efficiency gains for operators and service companies alike. Experience gained from milling operations using CT instrumented with real-time data enabled measurable improvements in efficiency. Post-job data analysis offered additional insights to improve methodologies and further unleash untapped efficiencies. Real-time bottomhole assembly data were collected during plug milling operations using a positive displacement motor. Critical downhole readings, such as CT internal and annular pressure, axial force (thrust), and torque were monitored during the operation to identify tagging of isolation plug targets, onset of milling, and stalls. The real-time data not only added confidence to event confirmation, but also increased the accuracy in estimating efficiency metrics such as rate of penetration (ROP) and stall recovery duration. Post-job analysis calculated the error and shortcomings associated with estimating event detection based on surface measurements. Additionally, error in event detection was tied back to inaccuracies in estimating efficiency metrics when relying on surface measurements alone. Analysis of downhole measurements in CT milling improves the precision of event detection and enables rapid reactions. Target tagging reflects instantly in thrust, and motor activation reflects synchronously in downhole differential pressures and torque, which together provide certainty of motor engagement on the target. Stalls reflect in differential pressure and torque spikes that coincide with motor specifications. ROP more than doubled by leveraging these event detection techniques throughout milling operations. New torque-thrust signatures were also identified to detect material interfaces. Changes in signature behavior indicated when the bit milled through one target and reached the next. This is particularly useful when the operator must mill through a target but stop at a subsequent, contiguous one. Post-job data also suggested that some events may have been mistaken as stalls during the operation, with downhole data confirming they were false positives. Finally, at operating conditions in the case study, a 7-second lead-time window was identified to anticipate and react to stalls. This highlights the importance of access to real-time downhole information, such as differential pressure, to avoid both stalls and false positives, and ultimately, to make breakthroughs in operational efficiency. Integrated analysis of downhole measurements during CT milling lent visibility to actual ROP, stall rates, and stall recoveries. These constitute important baselines against which any improvement in efficiency must be compared. The methodologies proposed here for event detection, with special attention to stall anticipation and milling interface detection, pave the way for smarter, more efficient operations.
Employing Innovative Distributed Temperature Sensing Technique for Conclusive Downhole Leak Detection via Coiled Tubing: A Case Study from Pakistan
Khalid, Aizaz (Schlumberger) | Briones, Victor (Schlumberger) | Ramondenc, Pierre (Schlumberger) | Mhiri, Adnene (Schlumberger) | Khan, Rao Shafin (Schlumberger) | Molero, Nestor (Schlumberger) | Kamran, Muhammad (Schlumberger) | Ali, Syed Dost (Pakistan Petroleum Limited) | Rashid, Kamran (Pakistan Petroleum Limited) | Mallah, Sohail Ahmed (Pakistan Petroleum Limited)
Abstract Leak identification across well completions is a crucial operation in the oil and gas industry. A failure of well barriers can result in uncontrolled release of hydrocarbons and pose major risks to personnel and environment. Downhole gauges are widely used to provide pinpoint measurements of pressure and temperature across the completion; however, those measurements alone are insufficient to properly diagnose single or multiple well integrity issues. Alternative well intervention methods are needed to qualitatively estimate the location and number of potential leaks. For the past decade, distributed temperature sensing (DTS) has been used in wellbore completions and surface pipelines with preinstalled fiber optic lines to identify leaks by monitoring and processing temperature profiles across the length of the installation. The proposed methodology makes use of a similar principle, relying on coiled tubing (CT) to deploy the fiber optics and conduct DTS integrity assessment in wells completed without fiber optic lines. This use of fiber optics inside a CT pipe also provides simultaneous real-time downhole measurements, which include CT internal and annulus pressures, and casing collar locator (CCL), for precise depth control and accurate correlation of well parameters. In the south of Pakistan, the tubing-casing annulus pressure of a high-temperature gas well increased to near flowing wellhead pressure at the tubing, giving a clear indication that at least one of the completion components had failed, resulting in flow of hydrocarbons to the annulus. Yet, the high wellbore temperature limited conveyance of conventional logging tools to assess downhole completion integrity. A thorough analysis of well hydraulics was first conducted to gather the possible options to identify the leak using DTS. This enabled the determination of a workflow aiming to create enough differential pressure to generate particular temperature disturbance. CT equipped with fiber optics was run and stationed across the complete wellbore length, and DTS data were acquired for approximately twelve hours under changing well conditions, including shut-in and flowing periods. The acquired temperature information for each phase, along with pressure information, helped to narrow down the location of possible leak points. This methodology enabled the identification of a single, major leak point located at an expansion joint in the completion. The operator was able to riglessly set an annular plug to restore integrity, thus saving significant workover cost and time.
- Asia > Pakistan (0.72)
- North America > United States > Texas (0.28)
- North America > United States > Alaska (0.28)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract The success of water conformance operations often depends on clear identification of the water production mechanism. Such assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water-bearing zones in an onshore well in Japan. The subject well experienced unexpected contamination of oil-based mud and completion brine which generated tight emulsions in the wellbore during the completion phase. Despite a thorough cleanout and perforations, severe damage was observed and mostly water was produced. With the presence of persistent damage in the wellbore preventing any logging tool use, DTS was selected as main diagnostic method, with the fiber optics being deployed with CT to ensure full coverage of the interval. Acquired temperature surveys were processed and matched with simulated profiles, which tested various scenarios of damage. Ultimately, results were used to drive the design of remedial actions. The following operational sequence was implemented: temperature baseline measurements (6 hr), brine bullheading through CT-tubing annulus at 0.2 bbl/min (22 hr), and shut-in (6 hr) for warmback. The long injection stage was required to ensure enough fluid was being injected across the entire interval while keeping the downhole pressure below fracturing pressure. Real-time DTS data during pumping and warmback indicated the presence of a high-intake zone in the middle of the interval. Below that section, only marginal temperature changes were observed, which may be a direct consequence of the low injection rate limitation. Post-job processing using numerical temperature simulation was performed to complement that analysis and quantify intake along the well. Temperature inversion against DTS response was conducted independently using two different simulators, both of which yielded similar profiles, confirming the soundness of this approach. The results not only supported the presence of high intake in the middle interval, they also showed that the bottom zone most likely took some fluid. Complementary information eventually pointed to the high-intake interval being the primary water-bearing zone. This analysis led to the selection of the remedial actions to be performed in damaged oil zones. This study demonstrates how integrated use of data from design, to job execution, to interpretation can change the perception of a well and how DTS can be a viable alternative to damage and water-production diagnostics in some extreme conditions when production logging tools cannot be used. Results of the DTS quantitative analysis provided local damage profiles along the well, which were critical to the subsequent planning of remedial activities.
- North America > United States > Texas (1.00)
- Asia > Japan (1.00)
- Research Report > Experimental Study (1.00)
- Research Report > New Finding (0.68)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Overcoming Production Logging Challenges in Completions with Mechanical Restrictions Using Distributed Temperature Sensing: A Case Study from North Pakistan
Mehmood, Amer (Pakistan Petroleum Limited) | Ali, Dost (Pakistan Petroleum Limited) | Mallah, Sohail Ahmed (Pakistan Petroleum Limited) | Rashid, Kamran (Pakistan Petroleum Limited) | Mhiri, Adnene (Schlumberger) | Ramondenc, Pierre (Schlumberger) | Khalid, Aizaz (Schlumberger) | Briones, Victor (Schlumberger) | Khan, Rao Shafin (Schlumberger)
Abstract Conventional production logging with electric line is sometimes challenged by the presence of mechanical restrictions in the wellbore. The fragility of production logging tools also impedes the use of electric-line coiled tubing (CT) with the risk of damaging tools across sections with little clearance. This study showcases conclusive flow profiling using distributed temperature sensing (DTS) via fiber optics deployed with CT in a gas condensate well where wellbore access prevented the use of logging tools. Flow profiling via DTS has been used globally in completions where fiber optic lines are permanently installed. Interpretation of those logs usually leverages months of acquired data to invert temperature information and obtain the evolution of flow distribution over time. The proposed methodology instead relies on hours of DTS acquisition through the temporary deployment of fiber optics with CT. A comprehensive sensitivity analysis on key unknown parameters is then performed using a fit-for-purpose thermal-flow simulator to match simulated and acquired temperature profiles, leading to a flow distribution of gas, condensate, and oil in the wellbore. Before the intervention, an evaluation study was run using a flow-thermal simulator to evaluate the expected sensitivity of wellbore temperature to poorly characterized downhole parameters, such as permeability, pressure, or skin. This allows determining the downhole conditions under which DTS is able to detect flow contribution for a specific candidate. During the operation, the CT equipped with fiber optics was stationed across production zones for a total of 06 hours. The data was processed and fed back to the simulator along with reservoir, well data, and surface rates. To further constrain data processing, pressure surveys were acquired during the CT run using a downhole gauge, both during flow and shut-in periods. Unknown reservoir properties were sensitized during data interpretation to obtain a match between acquired DTS profiles and simulated wellbore temperature evolution, which, in turn, yielded an associated flow distribution. The matching exercise being an open-ended mathematical problem, several scenarios were considered, and their results checked against further production characterization of the wellbore and the field. The proposed case study illustrates how this methodology enabled logging in a mechanically-restricted zone and helped determining that the top interval was not contributing to flow. Flow profiling can be performed using a wide range of complementary logging tools, but the evolution of completions over the past few years is increasingly introducing mechanical restrictions that prevent the conveyance of such tools altogether. This study demonstrates that DTS can be a viable alternative for assessing zonal flow contributions. It also discusses the conditions under which this methodology is achievable.
- Asia > Pakistan (0.65)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
Abstract When performing matrix stimulation treatments, coiled tubing (CT) is a preferred placement technique due to the ability to spot fluid in front of the target zone(s). This method becomes a key solution when formation heterogeneities require a very selective fluid placement strategy. In today's industry, the most common approach is to design a treatment with volumes of stimulation and diverter fluids that are determined largely based on local practices. Often, it amounts to targeting a uniform stimulation, thus requiring a predefined amount of treatment fluid per length of total pay zone. That approach, although widely used and accepted, may not necessarily yield an optimum stimulation. We present an alternative technique that relies on the accurate quantification of fluid placement along the formation in order to define the respective volumes of stimulation and diverter fluids to be pumped. This method relies on the analysis of the distributed temperature sensing (DTS) data recorded by a fiber-optic line enclosed inside the CT and data processing through a fast interpretation algorithm to yield a zonal coverage profile. During a job, DTS data corresponding to the preflush can be used to estimate the initial placement distribution across the pay zone. This allows stimulation engineers to determine the best strategy for the subsequent well stimulation treatment, including fluid volumes and placement sequence. After every major pumping stage, a new DTS analysis assesses how the formation reacted to the treatment, improving placement strategy. This method has been used in multiple matrix stimulation treatments of injector and producer wells. The described innovative approach allows engineers to make more informed decisions between stages, optimizing fluid resources, fluid placement and, ultimately, stimulation effectiveness. It also leads to noteworthy advantages when designing new acidizing treatments, as companies can build on previous experience from similar wells and fields.
- Europe (1.00)
- Asia > Middle East > Saudi Arabia (0.68)
- North America > United States > Texas (0.46)
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 98/6 > Wytch Farm Field > Sherwood Formation (0.99)
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 98/11 > Wytch Farm Field > Sherwood Formation (0.99)
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 97/15 > Wytch Farm Field > Sherwood Formation (0.99)
- (7 more...)
First Real-Time DTS Inversion Job Worldwide
Lopez, Victor H. (Pemex) | Castillo, Marco A. (Pemex) | Custodio, Rafael (Pemex) | Worden, Sarah (Schlumberger) | Romandia, Miguel Gerardo (Schlumberger) | Ramondenc, Pierre (Schlumberger) | Rueda, Felipe L. (Schlumberger)
Abstract The production curve of the main Mexican offshore fields has been decreasing rapidly year-on-year, representing a challenge to the eighth-largest oil producer country and an opportunity to implement new techniques for workover (WO) operations to increase production recovery. Within the most common WO activities developed in offshore Mexico is acid stimulation of carbonates, which was developed as pumping a large volume of fluids (solvents, HCl 15%, etc.) with minimum control for zonal coverage. Conventional coiled tubing (CT) jobs have improved this technique with the use of impact jetting tools to remove damage at the tubular and perforation holes and placing the treatment in the desired area. The estimation of fluid injection per zone has been evaluated using radioactive traces. However, the estimates of where the fluids go lack accuracy, and the radioactivity poses additional risks related to hazardous material handling. In 2009, a new interpretation technique to evaluate the treatment zonal coverage appeared that used CT with fiber optics. This distributed temperature sensing (DTS) enables the equipment to record temperature readings at several predetermined depths over time creating a survey that identifies, qualitatively, the admittance of the treated pay zones based on the formation’s cold-down/heat-up effects. Unfortunately, this technique had some limitations as the data recorded needed to be converted, interpreted, and then translated into common oilfield language in the form of graphics and data tables. The time to get a final result from the readings to the customer was so long that the window to modify the current treatment to improve the well response was, on most occasions, already closed. DTS inversion brings a "real-time DTS matrix stimulation evaluation product" by using an inversion algorithm coupled with a fluid placement model to accurately quantify the amount of treatment placed across the treated zones of the well. A detailed case history from an offshore Mexico well describes the first worldwide real-time DTS inversion job and illustrates the workflow and advantages of this technique. The results from the technique showed a direct match with a previous evaluation of the formation through production logging conveyed on Wireline tools.