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.
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.
An ultimate objective is specified to overcome the oil productivity deterioration in a cased hole producer that was drilled throughout by means of oil-based mud (OBM). Significant problems can be caused by OBM invasion into the reservoir and/or contamination by the OBM interacting with completion/formation brines in the hole. In this study for designing an optimum remedial program, a series of laboratory works were conducted using reservoir cores to understand accurately the damaged conditions/location at the site. For this study of a cased hole well drilled throughout by OBM, an unexpected low oil productivity was assumed with non-negligible water production. Multiple reasons were considered such as near-wellbore formation damage (including wettability change, emulsion blockage, etc.) or plugging in certain sections of the cased hole. To identify the main reason, return permeability tests (RPTs) were performed for several contaminating combinations: OBM versus formation/completion brines, or reservoir oil. Comprehensive evaluation determined the mechanism that caused the problem. Simultaneously, a bottle-test (BT) was conducted to evaluate if a micro-emulsion wellbore remediation fluid would dissolve the contaminated material. The RPTs indicated that minor OBM invasion occurred for the formation-brine-saturated core (RPT-1), and significant invasion for the core saturated with base oil (RPT-2). In the RPT-1 core, most OBM was trapped at the inlet-side core. This reduced the invasion, and the return permeability could maintain 93% of its original value. In contrast, the inlet/outlet surfaces of the RPT-2 core were cleaner than those of the RPT-1 core. This revealed that the OBM had invaded the RPT-2 core. Consequently, the return permeability dropped down to 32% of the original value. The BT showed that the multifunctional single-phase emulsion fluid could dissolve the sticky, contaminated material caused by mixing OBM and the completion brine. The contaminant strongly adhered to the glass tube wall and was quickly detached, creating flocs that could not be removed by solvents such as toluene. Contact angles on the tested cores were measured to understand measured area. These findings were useful for optimizing a remedial program: a two-staged operation consisting of removing contaminants from the cased hole followed by soaking for dissolving the invaded OBM near the wellbore. This study provides the valuable findings of laboratory evaluation of OBM-related damage in the cased hole well. The clarification of problem mechanism and location could be essential data for appropriate remedial design. A single test that screened effective dissolution-fluid was a part of remedial job design, but not enough for optimizing the design. This comprehensive evaluation approach of the RPT and BT demonstrated the most likely bottomhole/near-wellbore situations to be taken into account.
An ultimate goal is to overcome the oil productivity deterioration in a cased hole producer drilled throughout by means of oil-based-mud (OBM). However, problematic location has not been exactly identified whether in formation by OBM-invasion and/or in hole plugged by contamination. Therefore, in our previous study, the return permeability tests were carried out and revealed two potential damaged region: formation and/or cased/perforation holes. The objective in this paper is to screen appropriate solvents to remove contaminants from the cased hole and perforation hole. Unexpected low oil productivity with non-negligible water production suspected multiple reasons such as near-wellbore formation damage and/or partial plugging in certain sections of cased-hole and perforation tunnels. To address the issue of low productivity under the situation of uncertainty in the damaged region, chemical treatment was planned in two steps: the first step for damage in the wellbore and perforation tunnels, and the second step for near-wellbore formation damage. Before the first step of the treatment, effective solvent should be screened for removing contaminants from cased-hole. Two solvents ("A" and "B") and xylene (for comparison) were evaluated by dissolution tests at reservoir condition. OBM and KCl-brine were injected into a dummy core holder to form synthetic contaminant in a mixing cell, and then solvent was injected to dissolve it at several mixing conditions. Each effluent was observed to compare dissolving process. Three mixing conditions were assumed by adjusting injection rate of each fluid: (1) OBM with KCl-brine and (2) solvent. This mimicked a series of contact situation in deviated hole. By solvent type, both candidates showed good dissolution abilities because most of sticky immovable contaminants were discharged from the dummy core holder. After disassembled to check on the inside, a little amount of residue was observed around the outlet cap. Moreover, the residue was not sticky and easily removed. According to visual inspection of dissolved contaminants in effluent, the solvent-A made flocs that had floatable characteristics. On contrary, the solvent-B extracted oily component followed by forming flocs. However, the solvent-B also formed fine silt that had sinkable but flowable characteristics. By injection rate, dissolution process was progressed identically in any step for the solvent-A whereas step-wisely for the solvent-B. Finally, it was concluded that both solvents could dissolve contaminants effectively. Comparatively speaking, the solvent-A seemed to be able to work regardless of the contact conditions rather than the solvent-B. In case of considering clean up flow, the solvent-A might be better than the solvent-B because of more of floatable flocs formed. This study provides practical remedy program and laboratory workflow. Tested solvents are commercially available, therefore, the operator can request the suppliers to perform a laboratory evaluation. However, such independent deliverables can allow insufficient comparative evaluation for screening the best candidate. In-house study demonstrated variation of dissolution process between two solvents. Its result can contribute viewpoints of flocs floatability that is sensitive in case of considering not only dissolution ability but also clean-up flow.
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