Production optimization is a term heard so frequently in the upstream oil and gas business today that it ought to qualify as a buzzword. This is for good reason, though, as production optimization is one of the most critical industry objectives in the coming decades. If the industry is to continue to meet world demand for cost-effective energy that will fuel economic growth, it will be essential to optimize current production - and slow the inevitable decline - from existing wells.

The baseline situation is this: While there is much debate on when individual countries will reach their peak oil production, many countries have already passed their peaks, and the remaining countries with known oil reserves are all projected to reach peak production by 2030 - most of them before that, according to a Douglas Westwood report. Big discoveries are unlikely to change this picture more than marginally, as extensive analysis by the late eminent geophysicist Dr. M. King Hubbert so clearly indicates.

Production from brownfields - mature fields that have passed their peak - represented less than 20% of world oil production in 1982, about 30% in 1992 and approximately 45% in 2002. By linear estimate to the year 2012, brownfields will be producing more than 50% of world oil, according to figures from Douglas Westwood and BP (see Figure 1).

Existing fields

Schlumberger has positioned its services to reflect the exploration and production (E&P) industry's emphasis on the development, rehabilitation and optimization of production from existing fields. So while we remain very active in exploration-related services, we have focused a major portion of our strategy on the production side of E&P. We are beginning to see this shift toward production development and optimization spending among our customers.

Field development most broadly embraces twin objectives - increase maximum production of a field while minimizing capital expense; reduce the inevitable decline rate of a field while minimizing operating expense. Proactively managing both well and reservoir performance is key to achieving these objectives and is only possible through a complete understanding of the subsurface.

Increasingly facing this specific challenge as production shifts into the brownfield sphere, it will be necessary for the E&P industry to leverage the following:

• Project management;
• Production-focused technology; and
• Reservoir knowledge.

In a competitive sense, any one of these could serve as a differentiator for an oil and gas or oilfield services company, and the advantage of excelling in two or all three of these areas should be obvious.
It requires a constant balancing act involving many complex variables to assure the efficient use of capital and operating funds, and it is essential that this process embrace a holistic - life of the field - perspective.

In this environment, the service companies' traditional focus on single-segment offerings is less and less relevant to meeting the critical needs of the customer. Increasingly, these needs involve multi-segment solutions with long-term management to optimize results. Large-scale contracts that cover longer periods and tie remuneration to performance are becoming the norm.

While it is impossible in this space to summarize all the recent innovations and groundbreaking technologies that are helping the industry achieve new milestones in optimizing production, a partial list would include:

• 4-D seismic that quantitatively monitors the movement of reservoir fluid over time;
• Tools capable of evaluating key formation properties from behind casing;
• Multiphase flow-metering systems delivering efficiency and unparalleled accuracy in well-flow phase measurements;
• Rotary steerable systems and geosteering technology to improve the cost-effectiveness and accuracy of directional and horizontal drilling;
• Intelligent completion technology that enables real-time monitoring and control of well producing zones;
• A wide array of software products allowing the integration, modeling and visualization of data with unprecedented speed and accuracy, including workflows permitting the quick, convenient visualization of multiple field development options;
• Controlled-source electromagnetic surveys to confirm the existence and extent of hydrocarbon-bearing zones in spite of volcanic, salt or carbonate facies; and
• Real-time measurement, modeling and collaborative tools supporting the knowledge management process, a key enabler of multi-disciplined solutions fully leveraging best practices.

Fundamental to the successful optimization of existing wells is the ability to measure relevant information, interpret the information and to implement engineered decisions in the appropriate timeframe. The concept of process-relevant time - information gathered, processed, interpreted and distributed to the right people to make informed decisions - places the value of the technology mentioned above into three different domains. Each reflects a different time scale. These domains and their associated time scales are: operational practice, seconds to minutes; production enhancement, hours to days; and reservoir management, months to years.

Following are some examples of the value of technology in each of these domains.

Operational practice

Service companies provide on-demand access via the web to monitor and control electrical submersible pump (ESP) systems (see Figure 2). Through ESP monitoring technology, operators can observe continuous real-time downhole pressure and temperature data. Control features include remote pump starts, stops and speed control.

Signal Hill Petroleum selected a surveillance and control system for ESPs on a well in a field considered very well developed and stable. The tool played an integral role in improving pump and well operations, and it helped increase oil production by 70%.
In the first 2 months after installation, the system helped identify damaged equipment in an adjoining well that was resulting in decreased production, as well as an operational practice placing undue stress on the pumping system. Pressure drawdown below the pump, after startup, indicated well pressure stabilizing at 300 psi. This raised concern, as it was about 150 psi higher than the design estimate.

Investigation led to a damaged choke being identified on an adjoining injector well, which was resulting in injection flows that were 31/2 times the desired water rate. The increased water cut from the producing well was wasting power and increasing costs. With repair of the choke and control of the injection rate regained, flowing pressure returned to a 200-psi level that was much closer to design criteria.

Production enhancement

A well surveillance and analysis service enables the identification of events or trends that warrant detailed diagnosis and analysis. By combining permanent downhole pressure and rate data, the service allows productivity (inflow performance) evaluation over time. Through production engineering analysis, remedial services options can then be identified to enhance well productivity. Kerr-McGee used a surveillance and analysis service from the startup of production as the company developed a significant discovery in the Gulf of Mexico. Early in the production history of one of the wells, the project team identified a high skin factor by analyzing pressure transients recorded on the downhole permanent pressure gauge. A high skin creates additional differential pressure across the completion and impairs well performance.

Diagnostic analysis confirmed that a reduced skin factor would substantially enhance well production. Thus, a recommendation followed that a remedial acid treatment be considered, when the well is next scheduled for downhole intervention.

Reservoir management

Subsurface modeling has over the years provided numerous challenges to reservoir characterization. The growth in available data has made it continually more difficult to evaluate interpretation results from each separate discipline. Permanent downhole gauge data for continuous readout of bottom-hole pressures provides real-time monitoring of the physical reservoir response to dynamic fluid-flow conditions that result from production. With the observed production and downhole gauge data available, the challenge for a geoscience team is to construct a geologic and numerical simulation model that provides realistic answers consistent with this new level of understanding (see Figure 3).

Continuing the Kerr-McGee case above, completion of the full-field simulation model enabled periodic comparison of the predicted and observed downhole pressure data. The general trend of the pressure decline was matched, and the specific performance of incidental pressure transients was used to validate reservoir parameters in the model. With this kind of reservoir simulation model, interference between wells could be modeled and an effective field development plan implemented. Based on this, one of the wells was repositioned through sidetracking to increase reservoir recovery.


The above cases exemplify but a few of the many ways in which key advances in production-oriented technology and the enhanced understanding of operational and reservoir issues that they afford are helping to leverage knowledge of the subsurface to optimize production and meet the field development challenges that increasingly will define the industry's success.