The primary physical mechanisms that occur as a result of gas injection are (1) partial or complete maintenance of reservoir pressure, (2) displacement of oil by gas both horizontally and vertically, (3) vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation, and (4) swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas. Gas injection is particularly effective in high-relief reservoirs where the process is called "gravity drainage" because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations. The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available. Nevertheless, a variety of opportunities still exist. First are those reservoirs with characteristics and conditions particularly conducive to gas/oil gravity drainage and where attendant high oil recoveries are possible. Second are those reservoirs where decreased depletion time resulting from lower reservoir oil viscosity and gas saturation in the vicinity of producing wells is more attractive economically than alternative recovery methods that have higher ultimate recovery potential but at higher costs. And third are reservoirs where recovery considerations are augmented by gas storage considerations and hence gas sales may be delayed for several years. Nonhydrocarbon gases such as CO2 and nitrogen can and have been used. In general, calculation techniques developed for hydrocarbon-gas injection and displacement can be used for the design and application of nonhydrocarbon, immiscible gas projects. Valuing the use of such gases must include any additional costs related to these gases, such as corrosion control, separating the nonhydrocarbon components to meet gas marketing specifications, and using the produced gas as fuel in field operations. The conceptual aspects of the displacement of oil by gas in reservoir rocks are discussed in this section. There are three aspects to this displacement: gas and oil viscosities, gas/oil capillary pressure (Pc) and relative permeability (kr) data, and the compositional interaction, or component mass transfer, between the oil and gas phases.
The Empire Abo field, located in New Mexico, US, covers 11,000 acres (12.5 miles long by 1.5 miles wide) and contains approximately 380 million stock tank barrels (STB) of original oil in place (OOIP). This reservoir is a dolomitized reef structure (Figure 1) with a dip angle of 10 to 20 from the crest toward the fore reef. The oil column is approximately 900 ft thick, but the average net pay is only 151 ft thick. The pore system of this reservoir is a network of vugs, fractures, and fissures because the primary pore system has been so altered by dolomitization; the average log-calculated porosity was 6.4% BV. Numerical simulations of field performance and routine core analysis data have indicated that the horizontal and vertical permeabilities are about equal.
Hydrocarbon production potential is often limited by constraints, and it is important that these constraints are understood and correctly represented when generating a realistic set of production profiles. The focus of this section is physical constraints in the system through which the fluid flows, but constraints applied because of reservoir management, contractual terms and economics are also highlighted. A production system includes the reservoir, wells, facilities and export system. Constraints within the system can be associated with any of the produced fluids (oil, gas or water) or a specific combination of them. For example, important factors to consider beyond the base deliverability of the reservoir are potential near-wellbore formation damage (skin), well tubing constraints, artificial lift availability, shared gathering system back pressures, flow line erosion velocity limits and facility capacities.
Activity scheduling is an important, integral part of production forecasting that can have a significant impact on the reliability of the forecast. Once the subsurface input has been established and agreed upon by multiple disciplines, the production forecast should be created taking into account system constraints, scheduled and unscheduled downtime and new activities such as well and field optimization, changes to facilities capacity or design and new wells and developments coming on production. Future development programs are a major component of activity scheduling. The timeline and production impact of the drilling program is estimated and layered onto the existing baseline forecast (commonly known as the "no further activity forecast"). This is typically done using type curves or a simulation model because the wells are not yet on production.
The production forecast should be consistent with the current reservoir drainage strategy and should include production from existing and new wells, side-tracks and well interventions. Short-term forecasts are most dependent on activity levels (number and timing of new wells and well interventions), while long-term forecasts are more affected by reservoir type and the above-mentioned subsurface assumptions. The above reservoir description should be based on all available field data, the quantity and quality of which will vary considerably from asset to asset depending on field location, maturity and the level of appraisal and surveillance. Key data includes 2D/3D seismic, well logs, PVT analysis, core analysis and well tests. Static and dynamic reservoir understanding, G&G and petrophysical interpretations, reservoir modelling and detailed analysis of both the reservoir and well performance are key factors in establishing the most optimal drainage strategy.
The following guidelines are provided to promote consistency in production forecasting and reporting. "Reporting" refers to the presentation of evaluation results within the business entity conducting the evaluation and should not be construed as replacing guidelines for subsequent public disclosures under guidelines established by regulatory and/or other government agencies, or any current or future associated accounting standards. Commercial terms refer both to those specified in Production Operating Agreements (POA) and to the tax laws existing in the affected countries. The POA typically describes the production entitlement of the operating groups and the mechanisms for sharing or recovering costs. The majority of this document focuses on forecasting the total production from a reservoir or field (gross volumes forecast).
The announcement comes 7 months after the two received permission to begin the tendering process for the project offshore Nigeria, which is expected to carry a peak production of 225,000 BOPD by 2022. The company will manage the position-keeping for the deepwater project offshore Nigeria, which is scheduled to start production later this year. KBR will head a joint venture with TechnipFMC and JGC to provide a basic design package and EPC bid for the Bonny Island expansion. The insights present an opportunity for significant operating and capital costs reduction. With these synopses of technical papers from OnePetro you can join the author for conferences in Kuala Lumpur, New Orleans, and Lagos, all while sitting in your chairs and without any travel expenses.
Noble’s first row of wells in its massive Mustang project is helping increase the operator’s DJ Basin output, and similar results are soon expected in the Delaware Basin. Devon Energy will be getting simpler and smaller by selling two no-growth assets—gas acreage in the Barnett Shale in Texas and oil sand operations in Canada. Its future is staked on growing oil production in the Permian’s Delaware Basin and three other unconventional oil plays. The Oklahoma City independent has a new-look portfolio and new operational and financial priorities. And now it has enlisted an energy research firm to leverage advanced analytics and machine learning to help get the most out of its assets.
The state-owned firm is looking within its home country, around Southeast Asia, and to the Americas—including shale—in an effort to maintain its forecast average yearly production of 1.7 million BOE/D over the next 5 years. The financial effects of the downturn are set to last at least a decade—which puts the industry almost at the halfway point. Petrobras and Shell have brought online the Lula field’s seventh FPSO as the firms continue to ramp up production from the pre-salt Santos Basin. The national oil company’s aim to lift oil and gas production and reserves over the next few years will rely on growth from big international projects, including those in Nigeria, Guyana, and the US. A new report predicts that US output will rise to a new record high of 12.1 million B/D in 2020.
After a long cooling off period, this dry-gas shale play is once again red hot. The state-owned firm is looking within its home country, around Southeast Asia, and to the Americas—including shale—in an effort to maintain its forecast average yearly production of 1.7 million BOE/D over the next 5 years. Encana CEO Doug Suttles assures that shale executives are acutely aware of the parent-child well challenge, and he doesn’t think it’s “a big threat” to the sector. The US majors plan to produce around 1 million BOE/D each from the basin, which has become a primary focus of their upstream operations. This industry is one often considered reactive and overly tradition-bound.