A Novel System That Diverts Away From Water Zone: Successful Case Histories from the CNOOC Field in Java Sea - Indonesia

Abstract

Getting good acid diversion in high water cut wells is always a challenge. Relative permeability effects due to high water saturations will push the aqueous base treating fluid into zones with high water cut. This leaves the oil zones untreated and results in dramatic increases in post stimulation water production.. While many fluid diversion techniques exist, this paper focuses on the successful application and results of a novel Viscoelastic Surfactant (VES) based fluid used as diverter in matrix stimulation treatments performed by CNOOC in its Java Sea, Indonesia wells. Introduction CNOOC in the Java Sea of Indonesia produces wells that are completed in both sandstone and limestone formations. Various completions methods have been employed including standard perforated completions, slotted liners, gravel packs, frac packs, and expandable screens. After the initial completion, the primary problems encountered in both sandstone and limestone formations are reduced production rate due to high water cut, and associated scaling. The primary production mechanism is natural water drive. Some of the fields also have water injection for pressure maintenance. The wells are generally completed over long intervals with multiple sets of perforations (see Figure 1). Most of the major platforms were developed in 1980's since then the reservoir pressure has declined by 50% to 70% (from +2000 psi to from 350 to 750 psi). Electrical Submersible Pumps (ESP) are used as the primary artificial lift method to maximize productivity from these high water cut (50%–98%)/low bottomhole pressures (350 psi-750 psi) wells. High water cut and scale deposition can result in rapid decline in flowing bottomhole pressure and production rates. If not treated in timely manner, the resultant drop in production rate results in ESP failures and costly workover operations. Acid stimulations are frequently carried out to remove damage and keep production above the ESP running limits. In most cases, wells are stimulated without pulling the completion (with the ESP installed). This reduces the cost of the workovers as well as reducing the dependence on the workover barges. The presence of an ESP in hole limits the diversion options during a stimulation treatment. Foam and polymer base fluids were previously used to achieve diversion. The results of these treatments were mixed and usually resulted in higher water cuts. It has to be theorized that the water cut increases because of relative permeability effects. In most cases, water has a lower viscosity and higher relative permeability than oil. When an acid treatment is performed, more of the aqueous treatment fluid will flow into the water zone then oil zone. Thus the bulk of the damage removal occurs in the water zone and even though the oil rate might increase, the increase is overwhelmed by the increase in water. So the key to stimulating these high water cut wells is to develop a method for diverting the acid away from the water zone into the oil zone. Without adequate diversion, high water cut and lower sweep efficiency are often the result of a stimulation treatment.

A New Methodology for Stimulation of a High-Water-Cut Horizontal Oil Well through the Combination of a Smart Chemical System with Real-Time Temperature Sensing: A Case Study of South Umm Gudair Field, PZ Kuwait

“…The real-time DTS interpretation is based on a methodology detailed in and (Tardy, Chang & Qiu 2011). On the basis of the temperature profile and its evolution in time, engineers identify which zones have been treated and which have not.…”

“…During each shut-in, the DTS profiles are acquired, processed and sent to an engineer with software performing a DTS inversion that yields the fluid placement profile with an algorithm such as the one described in and (Tardy, Chang & Qiu 2011). Based on the interpretation, corrective actions may be taken on the subsequent treatment steps, with the goal of optimizing the treatment objective.…”

“…To investigate this assumption, an acid placement simulator was used. The simulator's models are described in (Tardy, Chang & Qiu 2011). The simulator specifies the actual treatment schedule, the reservoir properties, and the wellbore geometry, and can predict parameters such as downhole temperature distribution and evolution, invasion profiles, skin profiles, wormhole invasion depth, etc.…”

“…Numerous papers have reported the success of deploying "smart fluids" whose viscosity builds up upon contact with water and breaks down upon contact with hydrocarbons ) (Soekama et al 2003) (Shnaib et al 2009), as a means of temporarily plugging the water zones and diverting the subsequently pumped acid to the next available oil zones. As explained in Chang (Chang, Thomas & Fu 1998), the material becomes a viscous gel when contacting brine and degrades when contacting oil.…”

“…This innovative approach enables engineers to deal with the uncertainty of predicting fluid placement along the well and to act in real-time following the interpretation of the DTS logs recorded during the treatment. The methodology for interpretation of DTS logs has been documented in ) (Tardy, Chang & Qiu 2011).…”