In Kuwait, the traditional approach to Field Development has been to drill wells, whether Vertical or Horizontal, Single or Dual, with completions dedicated to either Production or Injection. However, as increasingly more wells are being drilled to develop the stacked reservoirs, surface infrastructure is growing in complexity with regard to Production Flowline routing, Gathering Facility location, Satellite Manifold placement, Water Injection distribution lines routing, and access road construction. Also, since the reservoir stack is a combination of areally extensive Carbonates overlying shale & channel sand sequences, optimum surface locations of Injectors for one reservoir is now increasingly conflicting with the optimum surface locations for the Producer of another reservoir.
The North Kuwait team presented options that could reduce the requirement for excessive wellbores for both new Producers and Injectors. One of which is the utilization of a single wellbore to both Produce Oil from one reservoir and Inject Water into another reservoir simultaneously. This novel approach utilized the most popular Dual Completion equipment, but rather than produce or inject concurrently from separate reservoirs or layers, production & injection are achieved simultaneously through either tubing string. Tubing movement calculations were made to ensure that the resultant axial tubing forces exerted by simultaneously injecting cold water and producing hot reservoir fluid would not cause the Dual packer to prematurely unset.
This unique completion has several advantages which include the production acceleration from an adjacent reservoir/layer that would have been postponed for the life of the Injector and the elimination of the drilling of a new producer to access the oil from an adjacent reservoir/layer to the target injection zone. Additionally, the elimination of the drilling of an Injector well if its optimum subsurface location is close to, or coincides with, an existing Producer from an adjacent layer, and the reduction in access road construction and location preparation costs. This strategy will significantly reduce Unit Development Costs while concurrently ramping up production levels. With simple conversion workovers, rather than drilling new wells, Oil Production potential that is presently unexploited in dedicated Injector wells can immediately be realized. Pressure support Injection can be initiated as soon as distribution injection lines are made available via similar conversion workovers.
As the world's population grows and economies develop, the demand for energy will continue to grow significantly. This increased demand is also being underpinned by the desire for cleaner source of energy to minimize impact on the environment. The International Energy Agency and many others predict that the world's total energy demand will grow by about 35% in 2030 from today's level. Crude Oil and Natural gas are estimated to account for nearly 60% of total energy supply through 2030 for a number of reasons. The growing attractiveness of global Natural gas development also supports the general consensus and forecast that Natural gas will overtake oil towards the middle of the century as a primary energy source. Natural gas is also being used in a variety of processes as feedstock, fuel, etc. Its contribution to world energy resources is growing leading to the concept that it is a bridge to the ultimate hydrogen economy. The flexibility brought about by growing importance of liquefied natural gas, LNG, is also changing the dynamics of the natural gas supply and demand equilibrium. The massive growth in global LNG demand and the challenging supply constraints are putting pressure on the industry to think of more innovative ways to harness and monetize stranded gas fields in a cost-effective and creative manner. Some schools of thought believe that as much as 40% or more of the total global gas reserves is stranded and needs to be brought to market creatively. Such stranded gas resources, found in deep offshore acreages and such remote locations are typically isolated from onshore processing facilities and may not be profitably developed by conventional means. This creates the niche application for the Floating LNG technology as creative way of monetizing the resources. The majority of the world's stranded gas reserves are located in the CIS (30%) and the Middle East (25%). Africa was third, with 16% of the reserves, and was followed by the Far East (13%), Latin America (13%), Alaska (5%) and Australasia (3%). The top-five countries for stranded gas are Russia, Iran, Nigeria, Saudi Arabia, and the Alaskan North Slope in the U.S. This paper seeks to identify and emphasize the role and contribution of floating LNG as a more effective way of having access to and monetizing stranded reserves and associated gas, in an environmentally responsible manner safely. This paper also reviews the current status of FLNG projects, to highlight the technical and commercial obstacles that still confront them, and offer insight into how these obstacles might be overcome.
Keywords: Floating LNG, Stranded Reserves, Natural Gas, Liquefaction
The goal of an oil field development project is to accelerate the hydrocarbon production and maximize the recovery at a lowest cost. For a thin oil rim reservoir with a large gas cap on top and a strong aquifer below, achieving such goal can be very challenging since recovery of both oil and gas shall be maximized. A successful project shall entail plan first to accelerate the oil production maximizing the oil recovery prior to the gas cap blow-down.
The maximum oil recovery factor achievable in thin oil rim reservoirs was evaluated for a Malaysian thin oil rim reservoir based on dynamic flow properties. The force balance between the gas cap expansion, aquifer expansion and viscous withdrawal was demonstrated by showing the model simulated water-oil and gas-oil contact movement. The understanding of the force balance progressively guided the field development project team to selectively re-activate some of the idle wells, to selectively place new additional infill horizontal wells, and to plan selective water and gas-cap gas injection in key reservoir sectors.
In this paper, the reservoir simulation study on simultaneous up-dip water and down-dip gas injection was reported. The downdip gas injection, injecting gas at and close to water/oil contact, was found to be able to impede bottom aquifer advancement, improve sweep and further enhance the thin oil-rim oil recovery. The gravity assisted injection technique could become a cost effective alternate for IWAG particularly for remaining oil rim which can be less than 10 m after the successful primary and secondary production.
Shale - No abstract available.
Belhaj, Hadi Arbi (The Petroleum Institute) | Lay, G.F. Terry (Vineland Electronics Ltd.) | Lau, Laura J. (The Petroleum Institute) | Lau, Richard Arthur (The Petroleum Institute) | Rahuma, Khulud Mustafa (Al-Fateh University)
Relying solely on traditional drilling technology to estimate the world's proven Oil Reserves denies the likelihood that billions of barrels of unfound oil lay just outside the industry's technological reach. With substantial financial and legal assistance and government support to develop newer technologies like Deep-Water Drilling (DWD), the major oil companies and the US White House are confident that new fields can be brought into production that should increase supplies and stabilize or lower energy prices. Each new find, they estimate, will help increase the world's proven oil reserves allowing investors and consumers to feel more optimistic about providing for their future energy needs. It is also hoped that this new technology will lead to safer, more economic and environmentally appealing exploration and production methods (Belhaj, et al)1.
Pertinent questions arise as to what impact BP's tragic oil spill may have on the future of Deep-Water Drilling and on the future of energy prices? Does industry have the technology to successfully and economically exploit fields using DWD? What role should governments play in regulating dangerous, environmentally unsound drilling practices? Should regulations be allowed to impede progress?
Identifying DWD as having a major influence on cost and being a critical parameter in any energy equation, the authors answer these questions and present two models that pessimistically and realistically describe the future role of DWD in places like China, India and Brazil over the next 50 years - places with growing populations and economies, but little government oversight.
Conclusions are reached with a discussion about the need for DWD in the current economic slowdown in advanced economies that have witnessed decreased oil demand and why traditional models affecting energy prices have been unsuccessful in predicting the current high energy prices.
Shale gas currently provides 20% of domestic supply, is targeted by half of the gas-directed drilling rigs, and represents the large majority of domestic resources. However, modern shale plays, their development strategies and their engineering analysis are young by comparison to those of conventional reservoirs. Uncertainty in shale gas reserves has significant implications at both the micro and macro levels.
Conventional reservoir engineering tools must be viewed as potentially inadequate (or even inappropriate) for the evaluation of shale gas performance primarily because of the extremely low aggregate permeability of these systems, but also because of other unique aspects of the systems. Reservoir modeling (simulation) has an important role as an assessment and prediction tool; however, the character of the reservoir (induced and enhanced natural fractures) must be considered, as well as the geological and fluid characteristics. Rate-transient analysis (modern decline analysis) techniques are also more rigorous and have been expanded and adapted to fit the uniqueness of shale gas production. Application of each method for shale gas is discussed, including methods and limitations. These two techniques more closely represent the physics of shale gas production, but their implementation is often prohibitive.
By way of necessity, much engineering evaluation is performed using Arps decline curve analysis. This technique is argued by some to be inappropriate due to a lack of theoretical support and demonstrated tendency to over-estimate reserves in tight gas systems. Given the limitations, practical methods exist to reduce error associated with its use. A newer decline method, power-law exponential, is also investigated.
Long range energy forecasts suggest that world demand for LNG would double by 2020. While much of this demand will be met by baseload LNG liquefaction plants, this growth trend is also leading to the evolution of new LNG market structures. This is evidenced by the emergence of mid-markets, principally regional markets which rely on smaller parcels of LNG than applicable to baseload plants, and exploit the opportunities offered by spot trades.
While onshore baseload projects (requiring long term Sale and Purchase Agreements) continue to be aggressively pursued, the emergence of mid-markets has generated interest in the monetisation of medium to smaller gas reserves. For offshore gas fields, the deployment of floating liquefaction units (LNG FPSOs) offers an interesting pathway to these emerging mid-markets.
A significant portion of the potentially exploitable gas reserves today is stranded gas. The pressure to bring these stranded reserves (estimated to be in the region of 4000 TCF) to the market is compelling. The LNG FPSO provides an attractive route to connecting smaller and medium size reserves to the emerging mid-markets. However, the initial deployment of LNG FPSOs is not without its challenges.
The paper overviews industry efforts at maturing LNG FPSO technologies to market ready status. It assesses the progress made on technology qualification for LNG liquefaction, LNG/LPG product containment and offloading systems. The need for functionality and reliability of these systems in the metocean environment (benign to severe) in the prospective development provinces has driven a sustained program of technology qualification by the proponents of the technology. The paper reports on the claims of these technology proprietors, and the industry's views of these claims.
The paper critically examines the concept and system critical issues relevant to LNG FPSO deployment, evaluates the principal technology and deployment risks, and explores avenues for the mitigation of these risks.
Concluding the above analysis, the paper assesses the potential of LNG-FPSOs to supply and stimulate the development of the mid-markets, and focuses, by way of example, on a notional opportunity in the Asia Pacific region.
Macroeconomic trends, geopolitics, oil prices and the depletion of known hydrocarbon reserves are both motivating and compelling petrochemical companies to venture farther offshore in search of new supplies. And because most new hydrocarbon reservoirs are discovered in ultra-deep (upwards of 5000ft / 950m) remote waters, companies are faced with unprecedented physical, environmental, technical and project management challenges:
- Physical environments are more hostile.
- Exploration and production are more complex.
- Environmental, technical, human and material risks are greater.
- Capital expenditure and expected return on investment are higher.
- Projects are more global and involve multiple stakeholders.
- Contracts are more complicated.
- Expertise is widely dispersed across a global ecosystem of specialized contractors, suppliers and partners.
- Pressure to implement stricter governance standards and enhanced risk-response capability is increasing.
- Investors seek to reduce time to first oil.
This paper examines:
- The impact of macroeconomic trends, oil prices and geopolitics on offshore capital investment strategies.
- The challenges program managers encounter when steering the planning, execution, governance, risk mitigation and delivery of projects involving thousands of globally dispersed multidiscipline participants.
- How a collaborative project management model underpinned by state-of-the-art technology can provide secure on-line access to a single source of information, enabling a globally dispersed project ecosystem create, collaborate and share information seamlessly while protecting Intellectual Property (IP)—from Front End Engineering and Design (FEED) to platform construction, assembly configuration, and commissioning.
- How dynamically updated performance dashboards provide a unique and reliable basis for risk mitigation, issue handling, prompt decision-making and enhanced risk-response capability.
- How all stakeholders reap measurable benefits and valuable time otherwise spent collating unreliable information from disparate systems can be used on high-value management activities that have a direct impact on the economic outcome of a project.
It concludes that the time has come for companies to make a paradigm shift away from inefficient, adversarial, proprietary, stove-piped information systems toward the use of integrated collaborative applications that foster partnership and trust while protecting Intellectual Property (IP) and enabling equitable sharing of risks and rewards.
Technology Focus - No abstract available.
Oil and gas reserves estimates that honor disclosure requirements of the US Securities and Exchange Commission (SEC) are critically important in the international oil and gas industry. Unfortunately, a number of exploration and production (E&P) companies have allegedly overstated and subsequently written down certain reserves volumes in recent years. In some cases, the consequences have been quite adverse. We document some of these cases of reserves overstatements and summarize the consequences. Reserves write downs are of obvious interest to numerous groups involved in the reserves estimation process and outcome, including estimators, managers, investors, creditors, and regulators. The magnitude and nature of recent overstatement cases, relative unfamiliarity with the SEC's inner workings, and the SEC's new reserves-reporting requirements increase the need to examine critically reserves disclosures and reserves overstatements.