Kansas Arbuckle Formation - (from Franseen, et al., 2003)

Since the 1910’s, several billion barrels of oil have been produced from the Central Kansas Uplift (CKU), primarily from carbonate reservoirs within the Arbuckle and Lansing-Kansas City groups (Figure 1). The majority of Arbuckle reservoirs of central Kansas were drilled prior to 1955 and constitute a series of giant and near giant oil fields. The significance of the Arbuckle to Kansas production and reserves is highlighted by the estimate that Arbuckle reservoirs have produced about 2.19 billion barrels of oil (BBO) representing approximately 36% of the 6.1 BBO of total Kansas oil production to date. Arbuckle reservoirs produce from 31 counties statewide with a significant portion of the total production coming from the 10 counties in the CKU region. Table 1 lists the 21 most productive Arbuckle fields and the cumulative oil production attributed to each. These fields represent approximately 56% of all Arbuckle production with nineteen of the fields lying on the CKU and the remaining two on the Nemaha Uplift in Butler and Cowley counties. Although the Arbuckle has been a prolific producing interval since 1917, annual production peaked in the early 1950’s at more than 68 million barrels and has declined to approximately 12 million barrels per year in 2002. Today, stripper production dominates Arbuckle production with over 90% of wells producing less than 5 barrels of oil per day and is very sensitive to commodity prices.

Figure 1: Map of Kansas showing major structural elements

The long production history and exploration/exploitation strategies have led to some commonly held perceptions about Arbuckle reservoir properties. These include: 1) Arbuckle reservoirs are fracture-controlled karstic reservoirs with porosity and permeability influenced by basement structural patterns and subaerial exposure. The weathering and secondary solution of the upper Arbuckle beds, due to subaerial exposure, is thought to have significantly enhanced porosity and permeability and created petroleum reservoirs in these strata. 2) The Arbuckle is composed predominantly of shallow-shelf dolomites. The process of dolomitization enhanced porosity. 3) Most of the oil and gas zones in the Arbuckle are contained in the top 25 ft, some are 25-50 ft within the Arbuckle and Arbuckle wells are characterized by high initial potential, steep decline rates, and production of large quantities of oil at high water/oil ratios. Thus, Arbuckle reservoirs typically have been visualized as an oil column on top of a strong aquifer. This conceptual model of the Arbuckle reservoir resulted in drilling and completion practices in which wells were drilled into the top of the Arbuckle with relatively shallow penetration (less than 10 ft.) and completed open hole. The geology of the Arbuckle is not well understood due to these drilling and completion practices along with the limited number of cores that have been taken.

Basic Information Pertaining to Water Shut-off Treatments Using Gelled Polymers
The majority of polymer treatments to control water production in producing wells are performed in fractured carbonate/dolomite formations associated with a natural water drive, such as the Arbuckle formation in Kansas. Gelled polymers are created when dry polymer is mixed in water and crosslinked with a metal ion (usually chromium triacetate or aluminum citrate). Gelation is controllable, ranging from a few hours to weeks. Slower gelation time allows for more volume and deeper placement. Different polymer systems are available from different service providers.

Service company experience seems to be the dominant factor in estimating how a particular formation in a given area will respond to gelant injection. The service provider must be prepared to alter the original design based on the ability of a formation to accept a viscous fluid. A formation injectivity test is important in determining any changes in the original design.

In many instances creating a pressure response during treatment is the single most important indicator of a potentially successful water control project. A slow, steady pressure increase over a period of time during pumping will tell the operator one of two things: 1) the formation is reaching fill-up of polymer into the problem zone, or 2) the reservoir temperature is causing the polymer to crosslink and build viscosity. In the Arbuckle formation in Kansas, in many instances, it is difficult to determine when a pressure response is occurring as the surface treating pressure is a vacuum throughout most, if not all, of the treatment.

Pressure response is a product of polymer volume, injection rate and gel strength. Altering any or all of these factors can improve the success of the treatment if reservoir resistance is not seen as the gelant is being pumped. Increasing polymer volume is typically the first step many service companies recommend if the Hall plot indicates only a slight increase of pressure near the end of the treatment. The advantage of pumping a larger volume is that greater in-depth reservoir penetration can improve the longevity and effectiveness of the treatment. The disadvantage of more volume is increased treatment costs due to longer pump times and additional chemicals. However, in most instances, the incremental per barrel cost of the extra volume is relatively low since many of the costs associated with conducting the treatment (well preparation, service company equipment, etc.) are already spent.

Usually injection rates are increased at the beginning of the treatment in order to determine how easily the formation can accept a viscous fluid. Recent research and field experience have shown that higher pump rates can improve the effectiveness of treatments in carbonates that exhibit secondary permeability and porosity features. Increasing the injection rate also reduces the service company’s field time, which translates into a cost reduction for the operator.

Increasing gel strength or gel viscosity is the third method for achieving a pressure response. This method is typically used at the midpoint of a treatment when the Hall plot shows no increase in slope or after several treatments in a particular field indicate the need for such action. Improving gel strength can be done by accelerating the crosslinking, increasing the polymer loading (concentration) of the gelant, or using a higher molecular-weight polyacrylamide.

Acceleration of the crosslinker in Marathon’s MARCIT^SM is accomplished by adding chrome chloride to the chromic triacetate. Mature gels can be formed in approximately 4-6 hours at a temperature of 90^o F with the accelerated crosslinker, as compared to the normal time of 16-18 hours. The advantage of this technique is that treatment volume may be significantly decreased in heterogeneous carbonates while the gel is placed into the highest permeability features of the formation. The disadvantage is that higher temperature reservoirs may cause the gel to prematurely set in or near the wellbore.

Increasing polymer loading will also improve gel strength. A 4,000 ppm gel contains 1.4 pounds of polymer per barrel of mix water. Increasing the concentration to 5,500 ppm will add 0.52 pounds per barrel, which is a nominal change in chemical cost. The advantage of high polymer loading is having a stronger gel that crosslinks in a shorter time.

Molecular weight also plays an important part in gel strength. Most treatments utilize polyacrylamides that have a molecular weight of 4-8 million. This medium molecular-weight polymer can be used for both high permeability matrix and smaller fracture systems. Service companies can also supply higher molecular-weight products that are designed for use in high conductive secondary features. Gels formed with this polymer will enter only the highest permeability sections of the reservoir where the water problem exists. The disadvantage of high molecular-weight gels is that in-depth reservoir penetration and subsequent water diversion may be reduced.

Table 1: Twenty-one major Arbuckle fields in Kansas.