Sand management/control

Implementation of Through-Tubing Technology in a Challenging Offshore Environment

A well drilled and completed in a marginal field offshore India produced only gas until the oil-bearing sands were perforated and the well was put on commingled-oil-and-gas production.

Fig. 1—Gauge-survey interpretation plot. TVDSS=true vertical depth subsea.

A well drilled and completed in a marginal field offshore India produced only gas until the oil-bearing sands were perforated and the well was put on commingled-oil-and-gas production. Through-tubing sand control was installed in the well, but, over time, formation pressure depleted and the well eventually died. The challenge was to unload and activate the well by use of gas lift in a commercially viable manner, avoiding expensive barge-based operations.

Well History

The LG field was the first commercial discovery in the XY Block, 10–15 km west of the Hazira coastline in the Gulf of Khambat. The field is approximately 38 km2 in an area ranging in depth from 10 to 25 m. The area experiences harsh sea conditions, with 6- to 8-knot underwater currents and tides of up to 6–8 m. The seabed channels and bars shift continuously. The seawater is extremely muddy, with near-zero visibility. The field contains excellent-reservoir-quality sands with porosities of 28 to 33% (average is 30%) and permeability of up to 4 darcies (average is 1.5 darcies). The field contains light sweet crude oil with gravity ranging from 38 to 45 °API. The undersaturated crude has a solution-gas/oil ratio in the range of 400 to 500 scf/bbl. Initial reservoir pressure in most of the reservoirs within the field ranges from 1,700 to 1,800 psia. Bubblepoint pressure is in the range of 1,600 to 1,700 psi. Because of the relatively high bubblepoint pressure, most of the sands are saturated.

LG was discovered initially as a gas field, and the wells were drilled and completed as gas wells across its various subdivided units on a lithostratigraphic basis. Well AB-5 was drilled and completed as a single selective two-zone completion. Because the field orientation was toward producing gas, tandem expandable shelter systems (ESSs) were deployed against the upper and lower sands (gas zones) with an inflatable isolation packer on the blank pipe between ESS sections. As permission was granted only to produce gas, provision was kept for possible future access to the lower oil-bearing sand. The well was put on commingled gas production from the B2 and B1 upper zones. The well eventually began producing water from the B zones; hence, it was decided to perforate the T1L oil-bearing sand for production. The well was perforated in February 2007 and was put on oil production. Because there was no sand control installed against the oil zones, the well was being produced with limited drawdown to avoid sand production. This was also accomplished in hopes of obtaining a sand-free production in absence of any sand control for other wells drilled and completed with a similar approach. Continuous sanding was observed post-perforation, which resulted in sand fill-up across the newly perforated oil sands. The well was immediately shut in, and several bailer runs were conducted to clear off the sand deposition against the perforation interval.

Well Suitability for Through-Tubing Sand Control

In order to implement the proposed technology, it was also important to justify the well by use of criteria including the following:

  • Operational Feasibility. Coiled-tubing units, barge-based operations, and workover rigs could not be justified commercially or operationally on an unmanned platform.
  • Bottomhole-Assembly (BHA) Restriction. Excessively long BHAs could have restricted the production rates from the well at later stages; therefore, a single screen installed against the perforations was the best solution.
  • Well Internal Diameter (ID). Because the technique involved screen installation on a bridge plug (inflatable packer) in the 7-in. casing, well ID for packer installation was an ideal condition for an inflatable-packer setting from a BHA-positioning point of view.
  • Deviation. In general, wells with zone deviations of less than 60° are suitable for through-tubing sand-control techniques. Well AB-5 has a maximum deviation of 30°.
  • Perforation Interval. Wells with interval lengths of no more than 200 ft (60.9 m) are believed to be good candidates in terms of adding skin to the system. Well AB-5 has 7 m of perforation interval, which indicates minimal skin induction in the system after screen installation.

It was decided to install through-tubing sand control with a through-­tubing packer and screens at the bottom conveyed on electric line. A through-tubing inflatable permanent-bridge-plug system was used to convey and install through-tubing sand screen (TTSS) downhole. The permanent-bridge-plug system for running screen below is a modified permanent bridge plug that incorporates a stinger to seal off the ID of the bridge plug to allow the plug to be inflated. Then, once the tool is inflated and the running tool disconnects from the plug, the bridge plug is left with a full-opening ID to flow through.

For a detailed description of the TTSS BHA, including the through-tubing electric-line-setting tool, the through-tubing test-pressure-equalizing valve, and the through-tubing pull disconnect with washers for the electric-line-setting tool, please see the complete paper.

TTSS Job Design

Stage 1: Screen Selection. The most critical part in screen selection is to obtain representative samples of the formation’s sand and to select an appropriate screen mesh size on the basis of the smallest representative sand stratum. The grain-size distribution often varies through a particular sand body, and usually from one zone to another. To ensure representative measurements, a number of samples are usually needed. Samples from conventional cores provide the best material on which to base the design. Sidewall samples are the next-best source. Bailed samples, or samples obtained from separators, can also be used, but may not be representative of formations because of size segregation of the sand particles. Information from offset wells should also be used in absence of other data. In any event, the sample sieved should be representative of the formation to be gravel packed.

Bottomhole sampling was conducted, and samples were collected to gather information on the grain-size distribution. The recommended screen size for retention of grains sized in the range of 399–508 μm was 12 to 20 gauge, with a median of 16 gauge, which yields approximately 400 μm. To be on the conservative side, 300 μm was found to be an appropriate size.

Stage 2: TTSS Installation. This stage consisted of two runs: a dummy run with a 2.5-in. gauge cutter and a TTSS run on an inflatable bridge plug.

Stage 3: Well Flowback. After successful installation of the TTSS, the well was put on controlled flowback to observe well performance. The well was slowly ramped up to the suitable choke to flow the well at 200 B/D initially for the first 24 hours. A lack of sand influx was confirmed. During flow, surface samples were monitored continuously to confirm any sand influx along with all other surface parameters. The well was gradually ramped up in stages.

Well Performance After TTSS Installation

The well performed sustainably and produced at a rate of 700–800 BOPD for more than 1 year after TTSS installation. However, in due course, additional skin was introduced into the system at the sand screen. Moreover, reservoir pressure depleted. The well experienced backpressure and was eventually loaded.

Pressure-Survey Details

To diagnose the well conditions and to obtain the exact measurements of fluids at various depths inside the wellbore, a static-pressure survey was conducted on slickline in 2012. Gauges were run in tandem and stationed for 15 minutes against each of the predefined station depths. Among the key observations of the survey were the following:

  • Both oil and water were present inside the wellbore, with oil and water gradients of 1.018 and 1.382 psi/m, respectively.
  • The oil/water interface was found at 934.31-m measured depth, with a water-column height of approximately 441 m in the wellbore (from midperforation).
  • In terms of potential, the well was found to be loaded and needed to be activated. (For an interpretation plot of a gauge survey, please refer to Fig. 1 above)

There were a number of challenges involved with activating/unloading the well; these are detailed in the complete paper.

Technique/Methodology Implemented

In an effort to avoid an expensive barge-based operation, a through-tubing gas lift (TTGL) technique using a straddle-packet gas lift system was proposed and finalized to unload and activate the well. The concept was to install a designed gas lift valve against the circulation sliding side door in the upper completion, and then to sting in between the two retrievable straddle packers to facilitate the gas lift while pumping gas through the production-tubing/casing annulus, thereby unloading and activating the well. For a detailed description of the components of the straddle-packer gas lift system, please see the complete paper.

TTGL Job Design

The entire operation for installing the TTGL and unloading and activating was designed and executed in four different stages:

  • Straddle-packer installation on slickline
  • Modular crane installation, commissioning, and load testing
  • Simulation
  • Well unloading and activation

For a detailed discussion of the work that went into each stage, please see the complete paper.

Operational Description

After flushing the surface piping with clean water by use of a C-pump and ensuring that no air was trapped in the surface lines, low and high pressure and temperature of the same was conducted against the annulus valve. The well was lined up to the production header for the duration of nitrogen (N2) pumping and well activation.

Guidelines for N2-Pumping Operation

Because N2 pumping and well activation were long-duration procedures (4 days were needed to activate the well and establish sustainable production parameters), the following guidelines were established for daily N2-pumping operations:

  • The well was always lined up at full open choke to the production header.
  • Daily N2 pumping was initiated with a minimum pumping rate (i.e., 200 scf/min), followed by gradually increasing the pumping rate depending upon stable well behavior and response.
  • Continuous samples were taken from the sampling point upstream of the choke and from the flowline.
  • In case of N2 being produced at the surface, N2 pumping rates were reduced to zero. N2 was allowed to become spent, followed by again gradually resuming the N2 pumping from the same minimum rate.
  • Intermittent N2 pumping and flowing of the well were conducted to allow the well to exhibit some flow.
  • N2 pumping was resumed in case the well ceased to flow, with the previous guidelines followed until the well was activated.
  • The well was flowed back and was declared to have the potential to flow by gas-assisted lift.

After 4 days of continuously performing intermittent N2 pumping and flowing of the well under these guidelines, the well was activated with an average drawdown of 180 psi, depending upon the simulations carried out.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24784, “Successful Implementation of Through-Tubing Technology (Sand Control and Gas Lift) in a Challenging Offshore Environment as an Integrated Development Strategy for Sustainable Development of Marginal Fields: A Case Study,” by Anurag Sharma, Alok Kumar Singh, Saurabh Anand, Arunabh Parasher, and Amit Sharma, Cairn India, and Sagar Kale, Weatherford, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25–28 March. The paper has not been peer reviewed. Copyright 2014 Offshore Technology Conference. Reproduced by permission.