The production of oil and gas, and the various processes required to make these products suitable for transportation, is an energy-intensive operation. Provision of electrical power, process heat and mechanical power usually requires the combustion of fossil fuels with resultant CO2 emissions to atmosphere. Flaring of hydrocarbon-based waste gases also creates additional CO2 emissions at production facilities.
In many instances, taking a more global approach to facility design can greatly improve energy efficiency and hence reduce CO2 emissions. Employing Cogeneration technologies to generate both power and heat, or to recover waste heat from processes to generate electricity, can both reduce site emissions and help ensure security of electricity supply. It may also be possible to use waste-gas streams as a fuel for a Cogeneration plant, reducing the amount of premium fuel required and simultaneously eliminating gas flaring, or to sell any surplus electricity generated, turning a waste into a potential revenue stream.
There are numerous ways to configure a Cogeneration plant, depending on the ratio between the power and the heat required by the facility, the available fuels or waste heat sources, the form of process heat required and the actual electrical power demand. This paper will examine some of the different well-proven potential Cogeneration configurations based on Gas Turbines, Steam Turbines and Gas Engines, as well as looking at how the newer technologies of Organic Rankine Cycles and Concentrated Solar Power can be employed in Cogeneration applications.
With potential overall fuel efficiencies in excess of 75%, Cogeneration can offer significant CO2 reduction over separate generation of power and heat, from either an on-site or off-site facility, or imported power from a remote third-party power plant. The paper will discuss potential CO2 savings for certain common plant configurations and fuels.
In this paper, we investigate how an integrated approach to long-term reservoir monitoring utilizing pressure and micorsiemic data can be used to identify changes in reservoir behaviour leading to compromises in reservoir integrity. In particular, we examine the observations related to a cyclic steam operation and subsequent loss of steam containment. Based on these observations, we suggest that the integration of real-time microseismic monitoring provides an opportunity to investigate reservoir integrity over long-term field development.
This paper illustrates the successful design, implementation and evaluation of cyclic steam stimulation pilot in heavy oil field of Sudan. This field contains heavy oil in multiple reservoirs of Bentiu formations of late cretaceous age occurring at epths of 550-600m. Reservoirs are highly porous (~30%), permeable (1000-2000 mD) and unconsolidated in nature. Fluid properties include viscous crude of degree API 15 - 17 and corresponding viscosities in the range of 3700 cp and 3000 cp at reservoir conditions.
In view of higher viscosities and consequently lower oil rates and envisaged meager primary recovery of around 18-20%, plan is made for thermal enhanced oil recovery (TEOR) application early to overcome the resistance to flow and maximize the recovery. As EOR processes are reservoir and reservoir fluid specific, therefore, it is prudent to understand the reservoir response to the steam injection before full field application. Cyclic steam stimulation has been implemented in eight selected wells spread over the field encompassing varying reservoir characteristics for understanding the efficacy of the process, acquiring the valuable data and operational experience. Equally important objective was to gain experience for minimizing the key risks, associated problems and challenges.
Wells have been completed with heat compatible casing and cement. Steam quality of 75% was injected for 6-12 days and wells were subjected to soaking of 3-5 days. Putting on production an improvement of three to five folds has been realized compared to primary production and first cycle is sustaining more than six months. Actual results are better than predicted in simulation studies with lower steam intensity of 120 m3/m compared to planned 160m3/m. Paper also discusses improvement in oil production and its variation with formation and fluid characteristics, formation thickness, depth of formations, duration of injection and soaking periods along-with response variables like oil-steam ratio and steam/water production. Operational challenges in preventing the heat losses in annulus, lifting challenges and sand production are also discussed.
Suliman, Abdalla Elhaj (WNPOC) | Bin Ngah, Ab Wahab (WNPOC) | Basbar, Ashraf Elfadil (White Nile Petroleum Co.) | Anua, Nor Aidil (Petronas Carigali Sdn Bhd) | Hashim, Salaheldin Tawfig (White Nile Petroleum Operation Company)
Many of Sudan's large oil fields suffer from low recovery factors and decline in primary production due to low oil gravity (<22 API) and viscosities above 100 cP. Many wells experienced premature water production. As such, Enhanced Oil Recovery project seems to be the option to improve oil recovery in Sudan.
Thar Jath field contains in excess of 1.2 billion STOIIP, 75% of the STOIIP comprises 20° API oil with 120-160 cP viscosity while the remaining STOIIP comprises 16° API with viscosity > 680 cP viscosity. The Full Field Review which was carried out through 2009 recognized that primary and secondary recovery could only recover, at best, 9.0% of the STOIIP with infill drilling. As such, a considerable number of Enhanced Oil Recovery (EOR) techniques have been assessed in order to recommend suitable EOR development project for the field, and to position the field as leading the way in Sudan. In the absence of a miscible gas option, dynamic reservoir simulation schemes were developed for the natural depletion, water flood, chemical, thermal and immiscible gas methods.
The three most promising techniques; ASP, steam flood/CSS and in-situ combustion were developed to optimize pattern spacing, injection rates and pressures for each technique. Thereafter, facilities schemes and notional costs were developed so that economic viability could be assessed to select the most preferred technique going forward. EOR has been found to be economically and technically feasible with highest economic recovery across all reservoirs from Steam technique. There is scope for thermal recovery to take recovery factor above 40% overall. The pilot test design study is on going with the objective to proof the concept and confirm scope of recovery from steam flooding prior to full field implementation.
The main tool for screening of EOR techniques is generally based on the criteria presented in a variety of tables and graphs given in the literature. These data are derived from the basic theory of multiphase fluid flow through porous media, reservoir simulation, laboratory experiments and existing field-scale experiences. The purpose of this study is to develop a procedure capable of combining the data extracted from different sources ranging from worldwide field experiences to the existing tables into a unified expert system. This expert system is based on Bayesian network analysis in order to sort the proper EOR techniques for further assessment by economical and environmental criteria.
A data bank has been gathered from worldwide EOR/IOR techniques and analyzed using data mining procedure which is then combined with extracted data from previously published screening tables. Bayesian network quantitative learning technique was applied to different data combinations from the data bank to train the network which is to serve as the expert system.
The produced expert system is also applied to the gathered data pertaining to 10 Iranian southwest reservoirs. The results show that, CO2 flooding can be the most promising among various EOR techniques, which is in agreement with a previous work. According to this study, considering reservoir characteristics, and excluding the economic limitations, CO2 flooding is considered as the most efficient EOR method for Iranian carbonate reservoirs under study.
The results show that Bayesian Belief network analysis can be successful in the prediction of proper EOR technique by providing sufficient Data to train the network.
Soleimani, Arash (Schlumberger Oilfield Services) | Penney, Richard K. (Schlumberger) | Hegazy, Osama (Schlumberger) | Bin Ngah, Ab Wahab (WNPOC) | Elhaj Sulliman, Abdalla (Sudapet Co Ltd) | Tewari, Raj Deo
Many fields in the Middle East suffer from low recovery and declines in primary production due to low oil gravity (<20 API) and viscosities above 100 cP. The studied field contains well in excess of 1 billion barrels in place with overall recovery expected to be less than 10% without EOR. 75% of the STOIIP comprises 20 API oil with 120-160 CP viscosity while the remainder comprises 17 API with 800 cP viscosity. Complicating matters, the three main sandstone reservoirs vary from braided fluvial streams in Upper formation (A), to thick sheet sands in the middle formation (B) and thinner sands separated vertically by thin shales in the Lower formation C.
In this study EOR techniques have been assessed for these three formations in order to recommend suitable development options for the field. Simulation schemes were developed for the following seven recovery mechanisms, including, water flood, chemical EOR - polymer and ASP, thermal EOR - CSS, steam flood, SAGD and in-situ combustion. Due to geological and fluid variation in these three formations, EOR mechanism behaves differently in terms of recovery for each reservoir.
The three most promising techniques, ASP, steam flood/CSS and insitu combustion were then developed to optimise pattern spacing and injection rates for each technique and for all three formations in this field.
Heterogeneity and geological factors have different impacts on the various EOR mechanisms, including convective methods like ASP and polymer flooding and convective-conductive methods like Thermal EOR. Overall, thermal EOR has been found to be more effective and economically feasible for this field, in particular for the heterogeneous formation with high viscosity oil. Different EOR techniques could be considered for each formation due to the variation in heterogeneity,
with recovery also changing from one formation to another due to fluid viscosity.
Different thermal schemes, for example varying the number of steam injection cycles before continuous steam injection, have been suggested for each formation in respect to its heterogeneity and oil properties. It is also noted that a SAGD EOR process can be more effective in certain formations in this field.
With the conventional decline in oil production from wells in the United States, additional sources of crude oil are required. One option supported by high oil prices is the application of enhanced oil recovery and advanced secondary recovery technologies to the currently producing wells. The U.S. onshore lower 48 crude oil in-place resource are vast. The question is how much of the oil can be produced using currently available technologies.
In order to answer that question, a detailed analysis was conducted in which the potential technical and economic production was estimated for several commonly used technologies. These include EOR technologies such as carbon dioxide flooding, polymer flooding, and steam flooding, as well as a variety of advanced secondary recovery technologies.
This analysis was conducted using screening and analytic tools which identify the recovery processes which are applicable to each reservoir in the onshore lower 48 and estimate the technical production from each reservoir. In addition, a newly developed economic model was used to estimate the technical and economic production which could be realized.
The results, data and opinions presented in this paper are those of the authors and not the companies with which they currently work. This paper describes the screening criteria which were used to determine the applicable technologies. The paper also describes the analytical tools used to estimate the technical and economic production for each of the assessed technologies.
Finally, the paper details the production levels which could be realized under a variety of technical and economic scenarios.
U.S. oil resources are distributed among some 70 known oil producing basins including those of the Lower-48 states, those in Alaska, and those in U.S. offshore waters. U.S. known original onshore oil resources are vast. Proved reserves peaked in 1970 at 39 billion barrels and declined to about 20 billion barrels as of the end of 2009. Approximately 13 billion barrels of these proved reserves are located in the Lower-48 states in onshore reservoirs1.
To date, cumulative production from known U.S. reservoirs has totaled more than 194 billion barrels, making the U.S. among the most efficient oil producers in the world. Still, billions of barrels remain as a target for potential recovery by various means.
The United States is currently producing a substantial percentage of its oil using EOR processes. As reported by The Oil and Gas Journa12 in 2010, the daily EOR production was 663,431 barrels per day from 193 projects. Of this production, the most substantial components, as seen in Figure 1, are CO2
miscible flooding and thermal flooding. These two processes make up 82% of the production and 80% of the existing EOR projects in the United States.
Zwaan, Marcel (Shell Intl E&P Co) | Hartmans, Robert (PDO) | Saluja, Jasmeet Singh (Shell Intl E&P Co) | Schoofs, Stan (Petroleum Development of Oman) | Rocco, Guillermo (PDO) | Adawi, Rashid (PDO) | Saadi, Faisal (Shell Intl E&P Co) | Lopez, Jorge L. (Shell Global Solutions International) | Ita, Joel (Shell Intl E&P Co) | Mahani, Hassan (Shell Intl E&P BV) | Qiu, Yuan (Petroleum Development of Oman) | Rehling, Johannes
PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to add significantly to the production and ultimate recovery from reservoirs.
Because of progress in technology in areas of data acquisition, processing and modeling techniques, well and reservoir surveillance data are increasingly used to optimize EOR processes. However, the interpretation of all data and integration into well and reservoir management workflows is still challenging. This paper describes the ongoing development of workflows for the interpretation, modeling and integration of surveillance data in three EOR projects.
The surveillance methods include geomechanical modeling, thermal reservoir modeling and monitoring through timelapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging.
A combination of growing energy demand, declining performance of conventional oil fields and attractive oil prices have renewed interests in both the heavy oil resources and the methods of exploiting them. However, their low mobility precludes relying on natural drive mechanisms for their extraction. Given that there are a very large number of EOR methods and to accelerate decision-making, a relatively simple screening procedure has been developed and implemented. Several simulation runs were conducted, investigating the effects of petrophysical properties and operating variables on performances of thermal and non-thermal flood processes. Then, a detailed economic analysis was performed to assess the economic feasibility of each recovery process/scenario. This work has contributed
significantly toward our understanding of the mechanisms of thermal injection in high permeability heavy oil reservoir. This is critical in the decision on the applicability of thermal recovery methods and its field application success.
Connacher's first oil sands project, the Pod One facility at Great Divide, has been operational since 2007. The successful SAGD project has produced approximately 7 million barrels of bitumen. During the past three and a half years, the impacts of certain predicted reservoir challenges and opportunities have become apparent.
While the quality of the oil sands in this first phase of Pod One is generally good, Pad 101 South in particular has geological zones that affect SAGD operation. This includes a bitumen lean zone, and a gas cap overlying the main bitumen channel/s. Early field results matched with detailed simulations have shown positive results in maximizing well pair production. For the purposes of this paper a lean bitumen zone differs from an aquifer in two ways. The lean zone is not charged, and is limited in size. The operation is also complicated by the fact the gas bearing zone has been depleted through earlier production.
Connacher's operating practice at Great Divide attempts to achieve a pressure balance between the 3 zones (rich oil sands, lean zone, gas cap) to reduce steam loss and maximize production rates. Reducing the pressure encourages steam chamber development growth horizontally and ensures that steam contacts the highly saturated bitumen areas. How this is achieved with the highest positive impact on well productivity is illustrated with operational data and analysis including the results of simulations that recommended the optimum operating strategies.