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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA laboratory study was conducted to characterize watershutoff polymer gels that are injected in the partially formed (partially matured) state into fractures (or other high permeability anomalies) that are in direct contact with production wells. Partially formed (<8-hr-old) 1X (0.5% polymer) chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gels showed much lower (as much as 100 times less) effective viscosities (17 to 30 cp) during placement in a 1-mm-wide fracture than "fully formed" (>15-hr-old) gels with the same chemical composition. Thus, partially formed gels exhibit substantially higher injectivities and lower placement pressures. This feature is of major importance during field applications where pressure constraints limit rates and volumes during gel injection. For gelants and partially formed gels that were 5 hours old or less, the rates of gelant leakoff through fracture faces were very low [about 0.013 ft 3 /ft 2 /d (ft/d)]. Thus, field applications that inject relatively small volumes of gelant or partially formed gels will generally experience small gelant leakoff distances, and the leakoff substance will not significantly inhibit oil from entering the fractures.During first brine injection after gel placement and maturation in 1-mm-wide fractures, the pressure gradient required to first breach the gel increased significantly with increasing polymer concentration in the gel -ranging from roughly 5 psi/ft for 1X (0.5% polymer) partially formed gels to 99 psi/ft for 3X (1.5% polymer) partially formed gels. For 1X gels, the breaching pressure gradient was greatest (~9 psi/ft) when the gel was aged from 12 to 24 hours before injection. Prior to exceeding the breaching pressure gradient, no detectable brine flowed through the fracture. During the limited brine flow after gel placement, most (>90%) of the gel remained in the fracture and did not "washout." The stabilized residual resistance factors (permeability reduction factors) for the first brine flood through the fracture (following gel placement and maturation) ranged from 750 to 22,000increasing with increasing polymer concentration and gel strength. The large stabilized (final and equilibrium) residual resistance factors for brine flow through the gel-filled fracture resulted from the brine flow occurring through relatively small channels (wormholes) residing in the gel. For the 1X gel, the stabilized permeability reduction factors (for brine flow in a gel-treated fracture) were comparable for formulations injected in the gelant state, the partially formed state, and the "fully formed" state.The CC/AP gels exhibited disproportionate permeability reduction during brine and oil flow through gelfilled fractures. During one experiment with the 1X gel, brine permeability in the fracture was reduced 166 times more than that for oil. In this case, brine was flooded first, followed by oil. For the 1X and 3X gels, the permeability reduction factor for oil flow remained constant (within experimental e...

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA laboratory study has shown improved performance for fracture-problem water-shutoff polymer gels that are formulated with a combination of high and low molecularweight (Mw) polymers. These gels are intended for application to fractures or other high permeability anomalies that are in direct contact with petroleum production wells. More specifically, we focused on evaluating the mechanical strength and improved performance of these water-shutoff gels for use when exceptionally large fracture apertures or large drawdown pressures are encountered. During our study, the gels were injected into laboratory-scale fractures while the gel was in a partially formed state. The flooding-experiment study involved the placement of partially formed chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gels in 1-to 4-mm (0.04-to 0.16-in.) aperture, by 2-ft-long, by 1.5-in.-height fractures where the fracture walls were 700 md unfired Berea sandstone.During the injection of a 1.5% high Mw and 2.0% low Mw polymer gel formulation, the partially formed gel fluid exhibited an effective viscosity of roughly 500 cp during placement in a 1-mm (0.04-in.) aperture fracture, and the matured gel exhibited exceptionally good fracture-plugging characteristics. The gel withstood 52 psi total differential pressure across the fracture length (26 psi/ft pressure gradient) for 24 hrs, while permitting no detectable brine flow through the gel-filled fracture. Subsequently when the differential pressure was increased to 175 psi (88 psi/ft pressure gradient), the gel rendered a brine permeability reduction factor in the fracture of 30,000. When placed in a 4-mm (0.16-in.) aperture fracture, a 25 psi/ft critical pressure gradient was required to render first and limited brine flow through the fracture containing gel of the same composition. After exceeding the critical pressure gradient, the stabilized permeability reduction factor imparted by the gel to brine flow in the fracture was 260,000. When increasing the brine flow rate through a gelcontaining 4-mm fracture from 500 to 8,000 cm 3 /hr (superficial velocities of 260 to 4,100 ft/d in the open fracture), the stabilized permeability reduction factor decreased from 100,000 to 39,000.The high and low Mw CC/AP gel exhibited significant disproportionate permeability reduction (DPR) effects during oil and brine flow through gel-filled fractures. The magnitude of the DPR effect decreased with increasing flow rate (and differential pressure). The effect also decreased with increasing number of flooding cycles with brine and oil. IntroductionThe objective of this investigation was to develop and characterize stronger and more durable polymer-gel formulations for water-shutoff applications in fractures or other multi-Darcy flow channels -especially for applications when large drawdown pressures or large aperture (>1.5 mm) fractures are encountered.This study was part of an investigation 1 of water-shutoff polymer gels that are to be injected in the partia...

A laboratory study characterized partially formed chromium(III)carboxylate/acrylamide-polymer (CC/AP) gels for water shutoff in fractures. These partially formed gels showed much lower effective viscosities during placement than comparable fully formed gels. During placement, leakoff rates through fracture faces were low for gelants and partially formed gels. During the first brine injection after gel placement, the pressure gradient required to breach the gel increased with the increasing polymer concentration. Most gel remained in the fracture and did not wash out. During brine flow through "wormholes" in the gel, stabilized residual-resistance factors (F rr ) were large and increased with increasing polymer concentration.

A multi-lateral oil-producing well A was killed due to excessive water production from Arab-C that is dumping into the Arab-D reservoir. Therefore, the communication between Arab-C and Arab-D where behind the expandable liner is urgently needed to be blocked. Several solutions were investigated in an attempt to stop this flow behind casing. This problem is always a challenging task for field operators. The effect of excess water production on the productive zone, Arab-D reservoir will be substantial in terms of changes in relative permeability of this zone and increased water saturation. This change in the reservoir behavior will result in reduction of well life. The dead well A is a valuable asset that needs to be effectively utilized throughout the producing life of the field. Therefore, remedial treatments to revive this well are of value in terms of strategic plan to maximize revenues. Although the rigless water conformance method in a multi-lateral oil-producing well is a difficult task to the oil companies because of reservoir heterogeneity, cross-flow, gel placement, and cost. Several options of water shutoff treatment are proposed to address remedial treatments for water conformance problems. The main objective of this study is to:Identify and characterize the source of produced water,Identify the chemical blocking agents that will flow through the water out zone, andidentify an effective technique to optimize the size and the placement of these chemicals. Challenges, design criteria, and field treatment evaluation are addressed in this paper. Introduction There are two general methods to minimize water production from Well A: rig workover and rigless operation using coiled tubing unit (CTU). Rig workover operations are very expensive, whereas the rigless operation using CTU is cost effective. A special procedure is needed for gelant placement to minimize the formation damage. The oilfield operator should rely on two distinct types of water production. The first type, usually occurring later in the life of a waterflood, is water that is co-produced with oil as part of the oil's fractional flow characteristics in reservoir porous rock. If the production of this water is reduced, oil production will decrease simultaneously. The second type of water production competes directly with oil production. This water usually flows to the wellbore by a path separate from that for oil (e.g., water coning or a high-permeability water channel through the oil strata). In the latter case, reduced water production can often lead to greater pressure drawdown and increased oil production rates. Obviously, the second type of water production should be the target of water shutoff treatments. Understanding and conceptualizing the reservoir is a key to:Distinguishing between the previous two types of water production.Successfully diagnosing the water production problem.Successfully implementing and designing water shut-off treatments.