Formation damage

Integrated Approach Identifies Formation Damage in Unfavorable Conditions

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.


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.


Source and location affect the selection of water-shutoff techniques, which are either mechanical or chemical in nature or a combination. No matter the operational approach, identification of the water zone is a critical step for any subsequent course of actions.

One method for the identification of water-producing zones is the use of production logging. Conventional production logging uses spinners and capacitance logs to detect water flow in the wellbore. Production logging tools (PLTs) can be deployed into the wellbore using slickline, wireline, or CT. To enable real-time evaluation of the acquired data, possible options include wireline, digital slickline, and CT equipped with either a conductor cable or fiber optics.

In damaged wells with high water cut, flow conditions can be unstable, with drastic changes in flow regimes. Once the well can no longer sustain stable flow because of reservoir depletion or damage in the absence of an artificial-lift method, a PLT becomes impractical. Furthermore, when wellbore conditions are complicated by the presence of debris or contaminants, data acquisition itself becomes difficult. Quantification of the damage profile and of water-producing intervals is of great importance in proper planning for subsequent operations.

To address these challenges, an alternative approach was used wherein DTS obtained through fiber optics deployed with CT was used to quantify damage profiles in severely damaged wells and to identify suspected water-bearing zones by integrating complementary information.

The proposed operational procedures are similar to those used for the quantification of fluid placement during acidizing operations: injection of fluid to cool down the formation and shut-in to measure rate and amplitude of temperature recovery along intervals of interest. In the present case, brine was used as the injection fluid. Quantification of the damage and injection-rate profiles are achieved by temperature inversion; the measured DTS data are matched with the simulated temperature response given by combined flow and thermal numerical models accounting for key formation and near-wellbore parameters.

The subject well was suspected to be severely damaged during the completion phase and yielded a relatively high water cut during flow test. This case not only highlights the validity of the proposed approach but also details the work flow and analyses performed to obtain meaningful data and to reduce uncertainty of the interpretation. The work also raises the importance of the integration of complementary data for a comprehensive understanding of well conditions.

Well Background

Well B was drilled as a development well sidetracked from an appraisal well (Well A). The target reservoir of the field is a sandstone, and there have been two oil producers in the field. Well A was drilled in 2015 (Fig. 1), penetrating five different oil-bearing intervals (1A, 1B, 2A, 2B, and 2C); pretest pressures implied an oil gradient, and the formation tester sampled oil at 2B while suggesting lower pressures at the top and bottom zones. Well B was sidetracked as a highly deviated well (up to 81° inclination) to maximize wellbore exposure to those five intervals, aiming to improve productivity of the well by accounting for the relatively tight nature of the formations observed in the offset wells. All the oil-bearing intervals except for 2C were considered for perforation, while 2C was not perforated in Well B because of reservoir-management considerations. Both Well A and Well B were drilled using oil-based mud (OBM) to improve drilling efficiencies, because the offset wells suffered from borehole instabilities during drilling when water-based mud was used. After the successful drilling of Well A, it was decided to drill Well B with the same OBM.

Fig. 1—Well correlation of the appraisal well and the development well. TD=total depth; TVDSS=true vertical depth subsea.


Well B was completed with a cemented liner and perforated using the ­tubing-conveyed-perforation (TCP) technique. Two issues were observed during the cementing phase: drillout of cement in the casing because of cementing failure and unexpected contamination (tight emulsion) of OBM and completion brine. The well was planned to be cemented for 7- and 5.5-in. liners; during the cementing operation, the cement wiper plug was not successfully pumped to the bottom of the well. The well then required drillout operations of the cement in the liner, degrading wellbore conditions and leaving metal and other debris inside the wellbore. Some metal debris was recovered at the surface, stuck to the casing-collar locator tool in subsequent wireline operations. Furthermore, the well experienced unexpected contamination of the OBM and the completion brine during displacement of the wellbore fluid. This left a significant amount of sticky material and tight emulsion inside the wellbore. To improve downhole conditions for subsequent wireline operations and the planned drillstem test (DST), the well was cleaned out using scrapers conveyed on the drillstring. After the clean-out operation, a cement-bond log was obtained using a tractor. The recovered tools were, however, covered by the contaminants. The wellbore was cleaned out multiple times again by circulation and scraper runs. The well was eventually perforated in underbalanced conditions by replacing part of the completion brine for nitrogen during delayed time of detonation through downhole circulation valve of the DST string using TCP for a total of 180 m (Sections 1A, 1B, 2A, and 2B). Phasing and shot density of the perforators were 72° and 6 shots/ft. After the detonation of the perforating guns, the well was flowed back a short time after the TCP job. During the DSTs, the well showed some oil flow initially with a sufficient productivity index. However, after the well was shut in multiple times, well productivity decreased and oil flow was reduced. Ultimately, the well unexpectedly flowed mostly water (with a water cut greater than 80%), and its productivity was degraded severely to approximately 25% of the initial productivity index. Plugging of perforation tunnels by the contaminants inside wellbore and some of inside and near-wellbore damage by the emulsion were suspected, but confident conclusions could not be drawn from the available data. The well was then suspended, and further diagnostics were run.

Issues that had to be addressed to establish commercial production of the well included identification of water-bearing and damaged zones and quantification for remedial actions. All four perforated intervals were considered to be oil-bearing zones before perforation on the basis of the openhole log interpretations considering an analogy with the two offset oil producers. Identification of the water-bearing zones was critical to subsequent remedial actions, especially for the selection of diversion methods to be used to avoid their stimulation. In addition, because four different, long layers were perforated, qualitative and quantitative damage profiling was also key to a successful stimulation design, considering selective stimulations with the diversion methods. Well diagnostics operations were planned to address all issues simultaneously and optimize the subsequent water-conformance operations.

After review of the available techniques for well diagnostics, CT with DTS was selected considering the following operational constraints:

  • Deployment method had to allow conveyance through the high deviation
  • Risk of sticking because of debris in the wellbore had to be mitigated
  • Multilayered, long target interval had to be logged
  • Low injectivity was required to avoid fracturing the formation

The majority of the complete paper is devoted to a discussion of the field case itself. Methodology is presented, as well as the operational sequence, for injection/warmback analysis using CT equipped with fiber optics (Fig. 2). Quantitative interpretation of measured DTS data is provided, as well as quantitative injection profiling and sensitivity analyses, for both low- and high-permeability cases.

Fig. 2—Conceptual representation of the operational sequence.


The main conclusions of the field case can be summarized as follows:

  • DTS can be used as a reliable alternative to production logging when wellbore conditions are not favorable.
  • Injection through the CT-casing annulus while keeping the CT stationary at total depth allows identification of the intake profile in real time, which later enables flexible optimization of operational procedures.
  • When injectivity of the well is suspected to be extremely low within the formation fracture pressure limits, a feasibility study should be performed before operational execution to evaluate under which conditions the cooldown/warmback methodology will be able to create enough temperature variations that can be detected with DTS and later analyzed to provide a reliable understanding of downhole flow patterns.
  • Real-time downhole measurements play a vital role not only in the optimization of the operational procedure but also in the acquisition of data that will feature sufficient quality to warrant reliable interpretation after the operation.
  • Quantitative analysis through temperature history matching can provide further insights about critical reservoir parameters, provided that a methodological analysis of fixed and variable parameters is carried out and sufficient complementary data is injected in the model to reduce the nonuniqueness of the problem to a strict minimum.
  • A particularly important lesson learned from this study is that, beyond a certain point, additional adjustments to variable parameters (such as the damage or permeability profiles) do not necessarily change the overall conclusion of the analysis when considering the intake profile.
  • Both bottomhole pressure and DTS history-matching efforts resulted in the same conclusion in terms of identification of water-bearing and damaged zones.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194284, “Pushing the Limits of Damage Identification With Coiled Tubing in Extreme Conditions: A Success Story From Japan,” by Nozomu Yoshida, SPE, Satoshi Teshima, SPE, and Ryo Yamada, INPEX, and Umut Aybar, SPE, and Pierre Ramondenc, SPE, Schlumberger, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper was peer reviewed and is scheduled for publication in SPE Production & Operations.