Kinder Morgan Energy Partners, L.P. (KMP) has created an impressive downstream business in an unusual area for a pipeline company. In fact, KMP started 2004 as the fourth-largest producer of oil onshore Texas.

KMP is one of the largest energy transportation and storage companies in America, operating more than 25,000 miles (40,000 km) of natural gas and products pipelines. It became an entity in 1997, and is now the largest publicly traded pipeline master limited partnership in the United States in terms of market capitalization. The company also has bulk terminals and power generation businesses.

So how is it that a pipeline company has become one of the largest oil producers in Texas? Management would tell you it came as the result of an acquisition and negotiation skills. The Reservoir Team would have you believe it was from the application of technology. The Production Group will suggest increased efficiencies. It was.

Acquisitions

In early 2000, KMP bought 100% interest in a relatively under-utilized CO2 asset and created Kinder Morgan CO2 Company, L.P. (KMCO2). The acquisition was in the form of a CO2 source field and pipeline distribution system. Rather than wait for an industry upturn to increase CO2 sales, an entry into the upstream business was at hand. But, unlike large upstream exploration and production companies that must explore for new reserves with significant risk, exploration would not be a component of the business plan. KMCO2 knew that mature oil fields already held left-behind known hydrocarbon accumulations. Further, KMCO2 has significant expertise in CO2 flooding technology. They knew the perceived risks associated with CO2 technology were dispelled in the preceding years in more than 40 industry projects. Concurrently, management found themselves with an opportunity to buy into another under-utilized asset, the SACROC Unit CO2 flood. As operator of the CO2 flood, KMCO2 theorized it might be able to guide this existing CO2 customer into more profitable territory. Kinder Morgan was successful in its bid and became operator of the Unit in mid 2000 with a 72% working interest.

SACROC

At the time of acquisition, the SACROC Unit was producing about 8,500 b/d of oil - with KMCO2 far down the list of recognizable operator names in Texas. With approximately 3 billion bbl of original oil in place, it classifies as a giant field covering 81 sq miles (209 sq km). The Unit was formed in 1952 for pressure maintenance following excessive withdrawals since its discovery in 1948. There had been 205 drilling rigs operating in a single month during 1950. Water and CO2 injection commenced in 1954 and 1972, respectively.

The Unit is completed in Pennsylvanian age limestone capped by a massive black shale. The gross pay thickness can reach more than 700 ft (213 m) with a net pay averaging 12% porosity and 33 md permeability. A typical well is 7,000 ft (2,135 m) deep and handles 2,500 bf/d. Injection is under a packer, and typically through selective perforations. The producers are a mix of openhole and perforated casing completions. Producers typically will flow for a good period of time before they are put on electrical submersible pump (ESP). Today, the Unit has more than 1,800 well bores. The majority were inactive at the time of acquisition.

Efficient utilization of assets

Most mature assets have a number of under-utilized assets. KMCO2 capitalized on those holdings upon the acquisition. One example was excess capacities in its CO2 recovery and recompression facilities. Arrangements with neighboring CO2 projects were made to handle their produced gas for a fee and/or a portion of the NGL and residue gas sales. Membrane separation technology is employed as a cost-effective means of separating CO2 from the hydrocarbon gas. This technology is now being heavily expanded in parallel with expansion of SACROC and neighboring projects. These once under-performing assets are now loaded and more cost-efficient.

CO2 processing is the second-costliest endeavor at SACROC after well work. As an example of operating cost reduction, KMCO2 increased field-gathering pressures to 400 psig. This, in turn, reduced compression requirements and electricity requirements by 25%. The wells continue to flow and respond to CO2 injection at the elevated pressures, and there has been no visible impact on oil recovery while field lifting costs have been appreciably reduced.

The P&A liability is now being managed as a long-term cost of operations and is being reduced. A consolidation of operations is now underway to eliminate those areas of the field with no CO2 future and concentrate on increasing production with a proper miscible flood in the most promising/high-graded reservoir areas.

Production turns around

In 2000, it was found that, as configured, only one of three original redeveloped areas/processes by the prior operator had any promise and the others were discontinued. A review of three decades of CO2 operations found several flaws. Original plans to conduct a miscible CO2 flood had quickly degraded to a less efficient, immiscible process. Early operations were plagued by inconsistent deliveries of CO2 from the supplier (Today, two pipelines supply the field and its neighbors with reliable quantities of CO2). The recycled gas contained an ever-increasing amount of contaminants, which degraded the miscibility of the system significantly. The Unit was basically "peppered" with CO2 with an ultimate solvent slug size at 13% hydrocarbon pore volume (HCPV), well below the current industry practice of +70%. Even if miscibility pressure had been maintained over many years, there never was enough CO2 delivered at any given time to develop a proper oil bank for the HCPV that was to be processed with the water-alternating-gas (WAG) injection operation. The end result through the mid-1990s was an immiscible or near-miscible CO2 flood with far less recovery than miscible operations would have produced. It is now recognized that a concerted effort is necessary to maintain the CO2 in a miscible state for efficient, measurable recovery to occur. To do this, a focused introduction of the proper amount of CO2 for a given HCPV target was required, and the CO2 needed to be contained by a water/pressure "curtain." A dense curtain of water injection is now placed around all CO2 project areas. Otherwise, miscibility pressure cannot be maintained in this relatively high-permeability carbonate reservoir as injectants slip off to unsupported or inactive reservoir areas.

These practices for achieving miscible CO2 flooding have increased production to its highest level in the past several years. As can be seen from the production chart in Figure 1, the miscible process appears quite healthy now. KMCO2, in addition to improving operating efficiencies throughout the system, has tripled production since acquiring SACROC in 2000. Miscible CO2 flooding approaches are expected to recover an additional 234 MMbo and extend the life of SACROC 25 years. SACROC alone carried KMCO2 to the rank of seventh largest on-shore oil producer in Texas at year-end 2003. Expansion within the temporarily abandoned acreage of the Unit will continue for many years to come.

Data is key

Data, and the acquisition of new data and new data types, has allowed much of the cost savings to occur in recent years at SACROC. KMCO2 has added to the original SCADA systems at SACROC. Its gas handling facilities are managed from a single room manned by two controllers. The facilities are now tied together with fiber optics and all necessary personnel within the company can monitor real-time operations from remote offices or home. Field facilities are being tied into the system, and the entire H2O and CO2 injection systems have SCADA to each well. Production systems are being reviewed for applications. Pressure, volume, rates, temperatures, gas compositions, vibration, warnings, failures, emissions and graphical trends provide a quick opportunity for multiple interrogations from any interested party. As an example, facility engineers can proactively pinpoint problems developing before a costly incident can occur, or make an adjustment to provide higher injection pressures. Safety personnel can determine what added measures may be needed for an alarm that is triggered. Production engineers routinely determine if a well is in need of some remedial attention or intervention, such as cleaning out a screen on injection headers or running or upsizing pumps. Reservoir engineers monitor injection scenarios and manage the flooding process better. The SCADA has even been successful in allowing inexpensive pulse-testing throughout the field to help identify downhole communication within the reservoir.

Cashflow, NOT just oil or lifting cost focus

In an honest attempt to meet their objectives, some companies create an incentive program that inadvertently places different employee groups at odds with one another. This occurs when management offers rewards for meeting lifting cost objective, oil production targets and reserve additions. This approach may cause employees to sub-optimize the operations. The reservoir department likely had the goal of increasing production and adding reserves while the production department was charged with reducing lifting costs. Often the goals were not relationally established and are found to be in conflict. These two goals must relate in CO2 operations to make headway on cashflow; otherwise everyone is stuck in the middle and neither goal likely realized.

As with any enhanced oil recovery process, the lease operating expense is more costly than the prior recovery process. There are some noticeable standouts in the cost structure. As mentioned earlier, the recycle of produced CO2 is one of the costliest processes within the Unit. It costs 12 times more to put an equivalent barrel of CO2 into the reservoir than a barrel of H2O. It costs 20 times that of a barrel of H2O for a purchased volume of CO2. There are certain offsets to higher lifting costs. Increased oil rates from flowing wells, from the energized CO2 cost noticeably less than those with artificial lift. It would behoove an operator to understand the interplay of every process cost in the operation. Management of the operational costs can then be conducted down at a basic element within the system. With the detailed level and proper allocation of cost accounting available within SACROC, a cashflow analysis by injection pattern can be performed within typical production analysis software. The injection pattern is where the reservoir processes can be managed. Under proper conditions CO2 is extremely efficient at mobilizing contacted oil; the denominator in the lifting cost equation. Lifting costs within CO2 project likely will not be reduced to that of a look-alike waterflood. Yet, a CO2 flood can be very attractive economically.

How to pull it off?

Spend some money to make money. Collect lots of data. Manage by cashflow. Do it at the injection pattern level. Don't simply focus on oil rate or lifting costs alone, or from the lease level. And it works. With acquisition of its second lease (majority interest in Yates Field) in late 2003, KMP has moved up from seventh to fourth largest oil producer onshore Texas. And, as Chairman/CEO Richard D. Kinder likes to say, "The best is yet to come."




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