Approach diagnoses, reduces water cut

Feb. 19, 2007
Oil field operators have employed numerous treatment methods, both mechanical and chemical, to reduce water production rates.

Oil field operators have employed numerous treatment methods, both mechanical and chemical, to reduce water production rates. But central to determining the treatment method is a cost-effective plan for diagnosing and solving the excess water production problem.

Water cuts in producing wells typically increase as oil fields mature with estimated water disposal cost of about $40 billion worldwide.

Treatments in two oil wells in Egypt operated by Khalda Petroleum Co., an international joint-venture company, illustrate successful jobs for reducing excess water cut.

Water production

Worldwide oil production is about 75 million b/d with water production estimates varying between 300-400 million b/d. The ratio of 4-5 bbl of water/1 bbl of oil produced is a conservative estimate.1

High water production increases both lifting and water disposal costs, while it reduces oil production. It also causes additional maintenance for production equipment and requires downhole treating for corrosion, bacteria, scale, and naturally occurring radioactive material (NORM).

Water-treatment costs are in the range of $0.75-2/bbl onshore and $1-3/bbl offshore.2

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A cost-effective plan for water problem diagnosis incorporates the following steps (Fig. 1):

  • Recognizing immediate problem.
  • Identifying water source.
  • Assessing problem.
  • Preparing optional and contingency solutions.
  • Evaluating all options.
  • Selecting best placement technique.
  • Implementing plan.
  • Evaluating and analyzing results.
  • Reacting as necessary to the results.

Recognizing the problem

Oil field operators need to recognize that there are two distinct types of water production.

The first type, usually occurring later in the life of a waterflood, is water co-produced with oil because of the fractional flow characteristics in reservoir porous rock. A reduction of this water production correspondingly would lead to reduced oil production.

The second type of water production directly competes with oil production. This water usually flows into the wellbore through a different path than the oil, such as from water coning, cross flow, or high-permeability water channels. In these cases, reducing water production often can lead to greater pressure drawdowns with subsequent increases in oil producing rates. Water shutoff treatments should target this second type of water production.

Three common indications of a water problem are: 3 4

  1. Some wells exhibiting a sudden increase in water cut.
  2. A well or pattern of wells may start producing at a much higher water/oil ratio than similar patterns.
  3. Plots of fluid production vs. time may show an abrupt increase in the water/oil ratio.

Identifying water source

Table 1 lists water production problems and treatment catagories.5 Each problem requires a different approach for an optimal solution. Achieving a high success rate when treating water production problems requires first correctly identifying the nature of the problem.6

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Identifying the nature and source of water production problems should begin with information already at hand. Some common methods used to diagnose these problems include:

  • Leak tests and casing integrity tests, such as hydrotesting.
  • Temperature surveys.
  • Flow profiling tools, such as radiotracer flow logs, spinner surveys, and production logging tools.
  • Cement bond logs.
  • Borehole televiewers.
  • Noise logs.

Many of these methods are used during routine surveillance of wells.

Several methods assess whether cross flow exists between strata, including pressure tests between zones; various logs for determining fluid saturations, permeability, porosity, and lithology; injection-production profiles; simulation; and seismic methods. If the operator does not know whether cross flow occurs, he should assume that cross flow exists.5

Logging is important for identifying water zones not only before drilling, but also after production has matured. Open and cased-hole logs can determine fluid saturations, identify water zones and water entry points, measure flow rates, and evaluate cement bond, downhole tubulars, and casing.

Avoiding water-handling costs is one way for operators to justify logging costs.

Water problem assessment

Table 1 lists the various water problems, prioritized and categorized from least to most difficult. The list is based on extensive reservoir and completion engineering studies and analyses of many fields,

The first three problem types in Table 1 (Category A, Problems 1-3) generally are easier to treat than the others in the list. Therefore, one should look first for these types of problems.

In contrast, the last three problems (Category D, Problems 11-13) are difficult with no easy, low-cost solution. Gel treatments will almost never work for these problems.

The intermediate problems (Categories B and C, Problems 4-10) result from linear-flow features such as fractures, fracture-like structures, narrow channels behind pipe, or vug pathways.


Proper perforation techniques, chemically or mechanically closing down high-permeability streaks, or separating the water from the oil downhole can solve excess water production problems.2 These methods generally can be categorized as chemical or mechanical (Table 2). Each method may work well for certain problems but may be ineffective in other cases.

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Conventional methods, such as cement and mechanical devices, normally should be the first applied for treating the easiest problems. These problems include casing leaks and flow behind pipe where cement can be placed effectively and in unfractured wells where impermeable barriers separate water and hydrocarbon zones.

Gelant treatments normally are the best option for casing leaks and flow behind pipe with flow restrictions that prevent effective cement placement. Both gelants and preformed gels have successfully treated hydraulic or natural fractures that connect to an aquifer.

Treatments with preformed gels normally are the best option for faults or fractures crossing a deviated or horizontal well, for a single fracture causing channeling between wells, or for a natural fracture system that allows channeling between wells.

Gel treatments can be categorized into three main types: permeability blockers, selective permeability blockers, and relative permeability modifiers.


When the water-producing zone is known, operators can use mechanical gravel-packed slotted liners selectively to produce certain zones. When the water-producing zone is unknown or when there are breakthrough or operating difficulties, they can use chemical methods such as gels, catalyzed silicate injection, or micromatrix cement. Chemical methods may need repeating as the production profile changes or the chemicals break down with time.

Selecting the optimum method should depend on the technical and economical evaluation of previous fields’ applications.

After implementing the treatment method, the operator needs to monitor the water/oil ratio regularly to determine success of the method.


A well in Kahraman-C field provides an example of a successful treatment for reducing water production.

The field is in the northwest part of the Khalda concession in the north part of Egypt’s western desert (Fig. 2). The field discovery well, Kahraman-C2, was drilled in 1992. The field currently has 60 oil producing wells and 18 water-injection wells.

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Kahraman-C mainly produces from Bahariya reservoirs that consist of laminated sandstone divided into two main horizons: Lower Bahariya (LBAH) and Upper Bahariya (UBAH). The Lower Bahariya is the main producing interval, providing about 70% of the field’s total production. The interval has good quality sand with a permeability up to 400 md and porosity of up to 24%.

The Upper Bahariya has lower quality rock consisting of thin sand streaks interbedded with shale and carbonate barriers. The operator is currently developing the zone with hydraulic fracturing, not only in Kahraman-C field but also in most other fields in the Khalda concession.

The Bahariya reservoirs lie at about -5,700 ft subsea.

Well Kahraman-C41 was drilled in February 2005 as part of the integrated plan for developing both the upper and lower Bahariya to the west of Kahraman-C field. The petrophysical analysis revealed 41 ft of good quality pay with an average 23% porosity and average 40% water saturation.

The LBAH in the well was as good as the LBAH that produces in the west area of Kahraman-C field. A repeat formation tester (RFT) was not recorded in this well, however, at almost the same drilling time, an RFT was run in the offset Kahraman-C46 well, which is 560-m away.

The Kahraman-C46 RFT showed pressures of 970 psi in the main producing sand, 1,500 psi in the wet sand right below the main producing sand, and 2,600 psi in the wet sand further downhole.

The initial LBAH intervals perforated in Kahraman-C41 were at 6,540-6,554 and 6,566-6,590. The test of the intervals with nitrogen lift produced all water at 960 b/d. The water had a 78,500-ppm chloride content, which is the same as in Bahariya water.

Review of the cement-bond log-variable density (CBL-VDL) log showed bad cement behind the casing with almost free pipe. This indicated that cross flow from the high-pressure wet sand into the low-pressure oil zone through the channels behind the casing may be causing the water problem.

To remedy the problem, the operator performed a cement squeeze with 17.5 bbl of cement through the perforated intervals. After drilling out the cement and cleaning the hole, the operator perforated the LBAH intervals 6,540-6,554 and 6,566-6,580.

The test of the well with nitrogen lift again produced 100% water at 222 b/d. The water contained 79,900 ppm chlorides.

A new CBL-VDL showed some cement improvement against the LBAH compared to the original CBL-VDL that showed almost free pipe.

The offset well in the same reservoir, 560-m away, produced oil with a low water cut, about 5%.

Based on this information, the conclusion was that water had cross flowed from the high-pressure wet sand to the low-pressure oil zone through the channels behind the casing after the initial perforation of the LBAH and during the first test. During that period, water had moved from the wet sand into the oil zone because of the high-pressure difference. This resulted in the 100% water cut during the second test after the cement squeeze job.

The cement squeeze job appeared successful, as indicated by the drop in production between the two tests, 950 b/d in the first and 222 b/d in the second.

The operator decided to complete the well and run an electric submersible pump (FC-450) that could handle up to 500 b/d and remove the water that had crossed flow into the oil zone. This proved to be the right decision because a test 6 days later produced 385 b/d of fluid with a 8% water cut or 354 bo/d.

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The well to October 2006 had produced a cumulative 260,000 bbl of oil, and the production rate in October was still 380 b/d of fluid with a 5% water cut or 360 bo/d (Fig. 3).


Another example of a successful water shut off treatment is from TUT field, in the Khalda Ridge concession on the border separating the Khalda and Agiba concessions (Fig. 2).

Well TUT-01 discovered the field in 1986. It currently has 21 oil producing wells and 3 water-injection wells. Production is from the AEB, Kharita, and Bahariya formations. TUT field is one of the largest in the Khalda concession, having produced about 15% of the total oil from the area.

The Kharita formation is a very high quality stratified sandstone with a permeability of up to 1,000 md. The formation normally has multiple zones, each having its own aquifer. The reservoirs produce under an active water drive. In TUT field, the Kharita lies at about -6,300 ft subsea.

Well TUT-33, drilled in April 1999, targeted the Kharita and AEB reservoirs. The petrophysical analysis revealed 16 ft of good quality pay in Kharita Zone II that has a 19% porosity, and 12% water saturation, and 19 ft of better quality pay in Kharita Zone I that has 28% porosity, and 13% water saturation.

The well, completed through the two zones commingled, produced with an ESP at an initial rate of 2,136 b/d of fluid with a 53% water cut or 1,004 bo/d (Fig. 4).

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In July 2000, the water cut reached 80% (Fig. 4). The operator, therefore, decided to work over the well to identify the water source. The belief was that Zone II was the source. Thus it was tested separately after isolating Zone I between two packers. Zone II tested 2,370 b/d of fluid with a 93% water cut or 166 bo/d.

Because of the considerable oil rate, the operator decided to keep producing from both zones commingled.

In mid November 2004, water cut reached 90% (Fig. 4); thus the operator again decided to test Zone II separately. The test produced 2,738 b/d of fluid with a 98% water cut or 55 bo/d. After isolating Zone II with a bridge plug, the operated tested Zone I on Nov. 17, 2004. That zone produced 1,846 b/d of fluid with a 93% water cut or 130 bo/d.

These tests indicated that the high-pressure difference may be causing cross flow from Zone II into Zone I. The operator, therefore, completed only Zone I with Zone II being isolated mechanically with a bridge plug.

Production during the next few days confirmed the cross flow. Five days after the completion work, the well tested at 1,835 b/d of fluid with a 41% water cut or 1,083 bo/d. The water cut continued to drop to 41% from 93% (Fig. 4).

The next tests continued to confirm the cross flow. On Dec. 12, 2004, the well tested at 1,962 b/d fluid with a 51% water cut or 961 bo/d. The well after about 2 years of production produces with 90% water cut, which is less than on the first test.

The well during 2 years has produced a cumulative 400,000 bbl of oil.


  1. Gino, D. L., and Phil, R., “New Insights into Water Control-A Review of the State of the Art,” Paper No. SPE 77963, SPE Asia Pacific Oil and Gas Conference and Exhibition, Melbourne, Australia, Oct. 8-10, 2002.
  2. “Water Cut Control Methods,” Petroleum Technology Transfer Council (PTTC),, 2006.
  3. Bailey, B., et al., “Water Control,” Oilfield Review, Spring 2000, pp. 30-51.
  4. Chan, K.S., “Water Control Diagnostic Plots,” Paper No. SPE 30775, SPE ATCE, Dallas, Oct. 22-25, 2005.
  5. Seright, R.S., Lane, R.H., and Sydansk, R.D., “A Strategy for Attacking Excess Water Production,” Paper No. SPE 70067, SPE Permian Basin Oil and Gas Recovery Conference, Midland, May 15-16, 2001.
  6. Elphick, J., and Seright, R.S., “A Classification of Water Problem Types,” PNC 3rd International Conference on Reservoir Conformance, Profile Control, Water, and Gas Shut Off, Houston, Aug. 6, 1997.

The authors

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Mahmoud Abu El Ela ([email protected]) is an assistant professor of petroleum engineering, Cairo University, and also works as a petroleum process consulting engineer at Khalda Petroleum Co. He previously worked as a research engineer at Woodside Research Foundation, Curtin University of Technology-Australia. Abu El Ela holds a BSc and MSc in petroleum engineering from Cairo University and a PhD from Curtin University of Technology. He is a member of the Egyptian Engineers Syndicate and SPE.

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Ismail Mahgoub is chairman of Khalda Petroleum. He previously served as chairman for Petrozeit Co., operations general manager for Khalda Petroleum, assistant general manager for Wepco Petroleum Co., and associate professor for Cairo University. Mahgoud holds a BSc in petroleum engineering from Cairo University (Egypt) and a PhD from Institut National Polytechnique de Lorraine, Nancy, France. He is a member in the Egyptian Engineers Syndicate and SPE

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Khaled Mahmoud works as a petroleum reservoir engineer at Khalda Petroleum Co. He holds a BSc in petroleum engineering from Cairo University. Mahmoud is a member in the Egyptian Engineers Syndicate and SPE