It is well documented that 3-D seismic improves the chance of success in conventional exploration plays. For unconventional resources some companies have a misconception that seismic is not needed because the geologic risk is very low. Other companies do not want the added expense of acquiring new data, or their position is too small to warrant seismic acquisition. But there is a new way to have access to seismic data that makes economic and logistical sense: Companies can license data for only the area they need, and it would be delivered fully interpreted and ready to use.
How multiclient works
To have a more comprehensive picture of the subsurface geology in an acquisition or drilling area, especially if a company’s acreage is “postage stamp” size and discontinuous in nature, E&P companies work together, on occasion, to acquire data over a larger area. They might participate in the underwriting of a multiclient program to increase coverage over their acreage. Multiclient companies work with multiple E&P companies to design and acquire a seismic program with optimum parameters, allowing the full suite of emerging shale technologies to be used to high-grade acreage and identify sweet spots to be developed with more success. The multiclient company owns the data, which reduces the exposure and financial risk to the E&P companies, and the E&P companies obtain a license to use the data. This allows them to create drilling programs and develop their acreage. E&P companies save money, and the multiclient company is able to license the data to other leaseholders as a way to recoup its costs.
A new model
The new model is to license 3-D seismic data in smaller increments and deliver fully interpreted data that have been incorporated with the required ties from outside the licensed area. This allows the buyer to use the data immediately. The deliverables could include depth maps to the zone of interest and other key formations as well as proposed wellbore plans and displays for presentation to partners and investors. The interpreter could have follow-up meetings to review and discuss the interpretation. The cost per square mile would be increased to cover the additional value added by the interpretation, but required mileage could be significantly reduced along with the time and hassle involved with independently interpreting the data. This saves time by eliminating these factors: determining the amount of data required for the interpretation, finding a consultant, communicating the requirements and understanding the products delivered by said consultant. The need for obtaining hardware and software for the interpretation and communicating those results to the operations, leasing, management, partner and investors will be reduced.
In this case, the interpretation is delivered at the time of the purchase and development drilling, and partner presentations and investor presentations will be supported for a period after the initial data delivery.
The economics of licensing the perfect amount of seismic data needed to image the acreage with critical well ties and regional geology incorporated is compelling. For example, for a 13-sq-km (5-sq-mile) contiguous lease tract, it is generally recommended that a company license at least 26 sq km to 39 sq km (10 sq miles to 15 sq miles) or more depending on the wells it wants to compare and the wells to tie into the surrounding geology. The cost can quickly climb to more than $500,000 or more, just for the data. This is without interpretation and ready-to-drill recommendations.
The company would typically hire a consultant, communicate the critical well ties and wait for the interpretation to be completed. This could take months. It might decide to forego the purchase and drill based on depths the geologist interpolates from surrounding wells. While this will generally work in a structurally noncomplex reservoir, there are instances where there is hidden complexity that might require numerous sidetracks, as in some portions of the Marcellus. Additionally, in many of the shale development plays the reservoir target zone is very thin, less than 15 m (50 ft). This makes it important to identify a fault that could put the wellbore out of zone. It is critical to be able to see ahead of the bit and instruct the drillers that there may be a 15-m downdrop or upthrown fault at a general “vertical section” position in the wellbore. Encountering a fault without any preconceived knowledge formulated from seismic data creates a challenge for geosteerers and drillers to get the wellbore back in zone without sacrificing time and, more importantly, the economic portion of the wellbore that can effectively contribute to the reserves.
Understanding how the economic success of a specific well can be impacted by 3-D seismic application and how that translates to all of the wells being planned for a given acreage position is imperative. Assuming average spacing of 40 acres or horizontals 201 m (660 ft) apart with required 100.5-m (330-ft) setbacks from lease lines results in about six wells/sq km (about 16 wells/sq mile). A typical small-volume seismic purchase from a multiclient company costs about $17,370/sq km ($45,000/sq mile). If the fully integrated
drill-ready interpreted volumes with support cost $21,230/sq km ($55,000/sq mile) and the license was restricted to only 13 sq km (5 sq miles), the total cost would be $275,000. That’s about $3,500 per well, or $86 per acre. This cost is equal to that of a well log, and it is much less than the cost to lease the acreage. The cost of seismic becomes an economic viability when the cost per acre or cost per development well is evaluated. Being able to avoid sidetracks or missed landing zones also is a cost benefit that can be hard to calculate on the front end, but avoiding these issues results in significant cost savings.
The example shown illustrates tying in a well and planning a subsequent well based on a high-quality 3-D seismic survey. Once a horizontal is tied into the seismic accurately, subsequent well plans can be produced that will predict the landing depth and landing inclination. Significant dip changes and/or faults might be encountered along the proposed well path.
A proposed deviation survey can be delivered directly from the seismic interpreter to the drilling team to efficiently drill a “no surprise” well. This might be more important in the development stage of an area and later if complex areas become an issue. It generally allows infill wells to be drilled without need to sidetrack on landing and stay in zone for longer. All of these add to creating a more economic development in an economically stressed economic climate.
Three-dimensional seismic interpretation has been shown to improve horizontal well placement, reduce the requirement for sidetracks and decrease re-drills due to unforeseen structural complications. When 3-D seismic is used in well planning and geosteering, it increases effective lateral length and can show subtle faulting not recognized in geosteering correlations, which affects completion effectiveness.
Recovering more for less is the ultimate goal for operators and service companies.
A pilot project in a major shale play represents one of the first attempts to measure how multilateral wells could deliver cost efficiencies in unconventional fields.
An ESP system features an electromagnetic design and better efficiency as production rates decline.