Development
Development in the oil and gas industry refers to the phase of a petroleum project that follows discovery and appraisal, during which the commercially confirmed hydrocarbon accumulation is prepared for production by drilling production wells, installing surface facilities (processing plants, pipelines, and export infrastructure), and executing the capital investment program required to bring the field to sustained commercial production; development is the most capital-intensive phase of the petroleum project lifecycle, typically requiring 5 to 15 years from discovery to first oil or gas and investment expenditures ranging from hundreds of millions of dollars for small onshore fields to tens of billions of dollars for large deepwater or oil sands projects; the development decision (also called the final investment decision or FID) is the formal commitment by the operating company and its co-venturers to proceed with development capital expenditure based on an approved field development plan (FDP) or field development program, which specifies the number and type of wells to be drilled, the production facilities to be installed, the field production profile, the capital and operating cost estimates, and the economic returns (NPV, IRR, and payback period) that justify the investment at the assumed oil and gas price deck; development is distinguished from exploration (the activity of searching for undiscovered accumulations) and from production (the ongoing operation of a producing field after facilities are installed and wells are on-stream).
Key Takeaways
- The field development plan (FDP) is the master document that governs the development phase, integrating geological and reservoir engineering characterization of the accumulation with production engineering well design, facilities engineering infrastructure design, environmental and regulatory assessments, and economic analysis into a single coherent plan that is submitted to the host government regulator for approval before significant capital is committed: the FDP specifies the number of production and injection wells (the drilling program), the well spacing and pattern (affected by reservoir permeability, pay thickness, and drive mechanism), the expected production plateau rate and duration, the ultimate recovery factor (percentage of original oil in place that will be produced), the type and capacity of surface processing facilities (oil and gas separation, water handling, compression, export pipeline or tanker loading), and the environmental management plan required by the host country's petroleum law; regulatory approval of the FDP is required in most petroleum-producing countries before development drilling can begin, and the approved FDP then serves as the contractual baseline against which actual development performance is measured throughout the production phase.
- Well spacing and pattern optimization during development planning directly controls the capital efficiency and ultimate recovery of the field, with spacing set by the balance between the drainage radius achievable from each well (determined by reservoir permeability and drive mechanism), the cost of each well, and the incremental recovery achieved by adding wells beyond the minimum required for efficient drainage: in a high-permeability offshore sandstone reservoir with strong aquifer drive, a spacing of one well per 200 to 400 acres may be optimal, with each well draining a large area through its long horizontal lateral and the aquifer maintaining pressure throughout the drainage cycle; in a tight gas sand or unconventional shale play, spacing of one well per 40 to 80 acres (or even 10 to 20 acres in the densest parent-child development wells) may be required because hydraulic fractures from each well are the only practical drainage mechanism in the nanoDarcy-permeability matrix; development of unconventional resources requires much higher well counts and capital expenditure per unit of production than conventional reservoirs, but the resource size (hundreds of billions of barrels of oil in place in North American tight oil plays) justifies the systematic well-by-well development approach that has become the model for shale oil development.
- Enhanced oil recovery (EOR) and improved recovery mechanisms are integral to the development plan of many fields where the primary drive energy (solution gas, water influx, or gravity drainage) is insufficient to recover more than 15 to 30 percent of the original oil in place, requiring secondary (water or gas injection) or tertiary (chemical, thermal, or miscible gas) recovery methods that are planned and implemented as part of the development program: water injection for pressure maintenance in undersaturated oil reservoirs (where pressure is maintained above the bubble point by injecting water at the same rate as oil is produced) is the most common secondary recovery method and is designed into the initial development plan in most moderate-to-high-permeability oil fields offshore; thermal recovery (SAGD for oil sands, cyclic steam stimulation for heavy oil) is the defining development technology for Canada's oil sands and California's heavy oil fields; miscible CO2 injection has recovered incremental oil from hundreds of fields in the Permian Basin and elsewhere, with the development plan specifying CO2 supply contracts, injection well locations, and the expected 5 to 15 percent incremental recovery over primary production.
- Subsea development systems are the dominant infrastructure architecture for deepwater oil and gas fields (water depths greater than 300 meters), where the cost and technical challenge of a fixed-bottom platform are prohibitive and floating production systems (FPSOs, semi-submersibles, TLPs, and spars) are used as the hub for subsea wellhead trees, flowlines, and risers: a typical deepwater development consists of 10 to 30 subsea production wells connected by 10 to 50 kilometer flowlines to a floating production storage and offloading vessel (FPSO) that separates the produced fluids, stores oil until tanker offloading, and re-injects produced water and gas; the capital cost of deepwater development is dominated by the FPSO (typically $1 to $3 billion), the subsea trees and manifolds ($50 to $150 million each), and the drilling campaign ($50 to $150 million per well), making deepwater FID decisions highly sensitive to long-term oil price assumptions and requiring Brent prices of $40 to $70 per barrel (depending on field size and infrastructure sharing) to achieve a positive NPV at a 15 percent discount rate.
- Development timing and phasing strategy determines how quickly the field is brought to production and how the production profile is shaped over the field's life, with operators choosing between a fast-development strategy (drilling all wells quickly to achieve early production plateau and rapid payback) and a phased development (drilling a limited initial well count to achieve first oil, then adding wells and expanding capacity as production data confirms the reservoir model and justifies additional capital): fast development maximizes NPV in a high oil price environment by front-loading production and cash flow but creates higher capital concentration risk if reservoir performance disappoints; phased development reduces the risk of committing full development capital to a reservoir model that later proves incorrect (as has happened in many optimistically-appraised deepwater fields where lateral reservoir continuity was assumed but proved absent) but sacrifices NPV by deferring production; the tension between these strategies is a central element of the development planning process, resolved differently depending on operator risk appetite, reservoir confidence, financing structure, and host government production-sharing agreement terms that may require minimum production commitments.
Fast Facts
The Kashagan field in Kazakhstan, discovered in 2000 with an estimated 13 billion barrels of recoverable oil, required 13 years and over $55 billion of development capital before achieving first oil in 2013, making it the most expensive oil field development project in history at the time. Its experience illustrates both the extraordinary complexity of large-scale field development (extreme sour gas content, arctic conditions, remote location, and novel reservoir characteristics required fundamental changes to the original development plan) and the critical importance of accurate development cost and timeline estimation at the FID stage.
What Is Development in Oil and Gas?
Development is the phase of a petroleum project in which a commercially confirmed oil or gas accumulation is drilled and equipped for production through the construction of production wells and surface processing facilities, governed by a field development plan that specifies the drilling program, facilities design, production profile, and economic returns justifying the final investment decision. Development follows exploration and appraisal and precedes the sustained production phase, representing the most capital-intensive stage of the project lifecycle with investments ranging from hundreds of millions to tens of billions of dollars depending on field size, water depth, and resource type.
Synonyms and Related Terminology
Development is also called field development, reservoir development, or production development in project management contexts; the field development plan is also called a development plan or FDP. Related terms include final investment decision (FID, the formal commitment by an operating company and its partners to proceed with full-scale field development capital expenditure based on the approved field development plan, typically requiring board-level approval, regulatory consent, project financing arrangements, and commercial agreements for the produced hydrocarbons), appraisal (the phase between exploration discovery and development during which additional wells are drilled and data are collected to reduce the uncertainty in reserves estimates, reservoir characterization, and production performance prediction to a level that supports the investment decision for full-scale field development), production well (a well drilled as part of the development program whose primary purpose is to produce oil or gas from the reservoir to surface, as distinguished from appraisal wells, injection wells, and exploration wells), enhanced oil recovery (EOR, any technique beyond primary depletion drive that increases the fraction of original oil in place recovered from the reservoir, including water injection for pressure maintenance, thermal recovery for heavy oil, miscible gas injection for light oil, and chemical flooding for intermediate gravity oil, all of which may be incorporated into the field development plan from the outset or added in later development phases as the reservoir response to primary production is observed), and reserves (the estimated volumes of hydrocarbons that are anticipated to be commercially recoverable from a discovered accumulation under defined conditions, which are the basis for the economic analysis in the field development plan and the reporting obligation to investors and regulatory bodies that governs the FID process).
Why the Development Decision Is the Most Consequential in the Petroleum Project Lifecycle
Exploration failure loses the cost of a few wells. Development failure or underperformance can consume billions of dollars and decades of corporate focus on a project that never delivers adequate returns. The FID locks in the architecture, capacity, and cost structure of the field for its entire producing life, with decisions about well count, facility size, recovery mechanism, and export route being essentially irreversible once construction begins. The development planning process is therefore where reservoir uncertainty must be most rigorously quantified, where the range of outcomes must be honestly communicated to decision-makers, and where the robustness of the project economics to downside scenarios must be tested before billions of dollars are committed.