It has long been known that heavy oil and bitumen recovery by SAGD and CSS processes is accompanied by significant production of acid gases, as well as solution gas. Since the old laboratory studies of aquathermolysis from the 1970’s and 1980’s, there has been considerable development in the knowledge concerning production of methane and acid gases from Athabasca, Cold Lake, Peace River, Venezuela and Utah oil sands. It is found that both GOR and gas composition may vary with the deposits concerned. There is considerable divergence of opinion about the chemical origin of some gases, notably carbon dioxide. This affects the methods of control that may be available in operating individual reservoirs, and the matter is discussed. Also discussed will be the means of taking advantage of aquathermolysis phenomenon. It has been shown that both the GOR and gas composition of a SAGD project can be calculated from first principles. This permits estimation of the daily throughput of hydrogen sulphide and therefore allows a prediction or control of the requirements for sulphur recovery. The control of scale in SAGD plants has also been achieved by application of the current state of knowledge. Finally, there are implications for hydrogen sulphide release during loss of well control, an important regulatory aspect.
Gonzalez, Laureano (Pacific Rubiales Energy) | Ferrer, Jose (Pacific Rubiales Energy) | Fuenmayor, Mac (Pacific Rubiales Energy) | Castillo, Nerio (Pacific Rubiales Energy) | Gil, Edison (Pacific Rubiales Energy) | Farouq Ali, S.M. (Heavy Oil Technologies Ltd)
In-situ combustion (ISC) is being carried out in the Quifa heavy oil reservoir in Colombia, employing four vertical inner wells and four deviated outer wells (inverted nine-spot pattern). Additionally there are four horizontal wells surrounding the pattern, which started producing one year before the combustion project was initiated.
In order to evaluate the project performance key parameters, such as volumetric sweep efficiency and recovery factor must be estimated. Therefore, it is important to have reliable values of drainage area and oil in-place volumes since they are basics for the calculations. Given the complex nature of this reservoir, with a strong water drive, the estimation of the drainage area, oil in place and the recovery factor posed a major challenge. The reservoir is characterized by abrupt permeability and oil saturation changes, resulting in water channeling and well interference.
This paper presents the methodology used to obtain the drainage area and current recovery factor of the ISC pilot project by using numerical reservoir simulation. It comprises the generation of oil drainage maps and cross-plots of what we called “Oil Displaced by Neighboring Wells, ODNW” as a function of time. This approach is more accurate than analytical methods for such complex reservoirs since those methods are based on ideal homogeneous reservoir conditions that assume uniform fluid displacement and a symmetrical advance of the combustion front.
Results are presented for the oil in place, the drainage area, and the recovery factor at one year of air injection. These results are compared with those derived from analytical methods. The methodology was designed to be readily applicable to similar heavy oil reservoirs worldwide.
Potential candidates for in-situ combustion (ISC) are screened in the laboratory by one-dimensional combustion tube runs or reaction kinetics experiments, or, ideally, a combination of both. While one-dimensional experiments are conducted at average reservoir conditions, reservoir heterogeneities may have an impact on the amount of fuel formed and, consequently, the amount of heat generated. Therefore, prior to field applications of any potential candidates, it is essential to understand the upper and lower limits of the reservoir rock and fluid properties, and how ISC functions within those limits. In this study, the effect of varying connate water saturation, initial oil saturation, clay content, permeability, and porosity are investigated with one-dimensional combustion tube experiments on different heavy crudes (8-20 API) with asphaltene content ranging from 10 to 18 wt% for different reservoir rocks including carbonates and sandstone. Process dynamics for good and poor ISC candidates are discussed in terms of effluent gas composition, temperature profiles and histories, total experiment time, oil recovery, behavior of fluid (oil, water, steam, and gas) front movements, and the level of oil upgrading at different reservoir conditions. Fuel consumption along with air requirements are analyzed for each experiment analytically. For good ISC candidates as identified by laboratory screening, the reservoir conditions that may lead to poor ISC field performance are estimated. It is observed that the reactivity of reservoir rocks at elevated temperatures (in the presence of oxygen) and the initial oil saturation are two important parameters that influence the fate of ISC. The findings considerably advance our understanding of field-scale ISC through the evaluation and interpretation of experimental data for different reservoir conditions.
Chemical EOR methods have become an increasingly attractive option for heavy oil reservoirs where thermal methods cannot be applied, like in thin reservoirs. The use of surfactants for heavy oil is only reported, both at lab and field scale, in a limited number of cases and mostly in combination with alkali to benefit from the generation of in-situ surfactants. However, operational issues (such as scale or corrosion) associated with the use of alkali as well as negative impacts on project logistics are often mentioned. The objective of this work is to demonstrate at lab scale the efficiency of alkaline-free surfactant-polymer processes in the context of heavy oil reservoirs.
The present investigation is focused on a Canadian heavy oil (14°API and 1400 cP) in representative reservoir conditions (high permeability sandstone, temperature of 35°C, low salinity). A dedicated synthetic surfactant formulation is designed using a screening methodology based on a robotic platform. Ultra-low interfacial tensions are evidenced from phase behavior and confirmed by spinning-drop tensiometry. Oil recovery performances of the surfactant formulation are then evaluated in corefloods.
Cores at Swi are first polymer flooded until no oil is produced to reach a residual oil saturation. Surfactant-Polymer formulations are then injected. Typical results show that additional oil is produced as a continuous oil bank (up to 100% ROIP depending on the slug size) and with a moderate adsorption if a salinity gradient strategy is applied (typically 0.2 mg surfactant per g of rock). This indicates that the surfactant is able to mobilize most of the residual oil. The results of this exploratory investigation show that alkaline-free surfactant-polymer processes could be applied to heavy oil reservoirs while minimizing operational issues. Complementary work will also be presented on optimization of the process through injection strategy improvement and surfactant dosage reduction as well as on extrapolation of the lab results to field-scale technical and economical feasibility.
Fuenmayor, Mac (Pacific Rubiales Energy) | Orozco, Diego (Pacific Rubiales Energy) | Nieto, Hollman (Pacific Rubiales Energy) | Urdaneta, Javier Alexander (Halliburton) | Gomez, Alberto (Halliburton) | Brothers, Lance (Halliburton) | Pedrosa, Herman Camilo (Halliburton)
The increasing demand for energy has increased the need for production of hydrocarbon. As a result, operators have exploited more difficult reservoirs (e.g., deeper wells, remote areas, mature depleted fields, and heavy oil reservoirs). Traditional methods are not sufficient for producing heavy oil; therefore, over time, enhanced recovery methods have been researched and developed.
In-situ combustion (ISC) is the oldest thermal-recovery technique. It has been used for more than nine decades for many successful projects. This method is basically the injection of an oxidizing gas (air- or oxygen-enriched air) to generate heat by burning a portion of resilient oil. Most of the oil is driven toward the producers using a combination of gasdrive, steam, and waterdrive.
High temperatures and the presence of corrosive gases involved during the ISC process can present significant challenges during well isolation.
Phosphate cement is a unique system capable of resisting corrosive attack, maintaining low permeability at high temperatures, and resisting the attack of carbonic acid.
One of the primary challenges was developing a special phosphate cement slurry capable of setting at low temperatures to minimize the waiting on cement (WOC) as well as developing properties sufficient for resisting future stresses. A special sodium aluminate thixotropic additive was used for the first time to react chemically with the pH of this special cement system to develop a quick and high compressive strength.
More than nine wells have been cemented with this system in Colombia with good results. These wells have been subjected to different stresses (production, steam injection, and ISC). This paper presents the successful application of advanced non-Portland cement slurry within the Quifa heavy oil reservoir in Colombia utilizing an ISC enhanced recovery method.
Cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) are successful commercial methods for enhanced oil recovery (EOR) used in Canada. Although SAGD exhibits higher oil recovery than CSS, it is more sensitive to reservoir heterogeneities such as top water and lean zones. In most cases, these baffles cause channeling in steam injection operations, thus leading to a high steam-oil ratio (SOR) and low injectivity. Therefore, recovering bitumen by using SAGD in a pilot well pad with such baffles in Long Lake has been a considerable challenge. To overcome the aforementioned issues, a hybrid process that combines CSS and SAGD (hybrid CSS/SAGD) is investigated in this study. Hybrid CSS/SAGD takes advantage of the benefits of both methods. During this process, all SAGD wells operate as cyclic injection/production wells. When the wells are shut in for a soak period, the injectivity of SAGD is highly improved. Simultaneously, the producer can also function as a heat source. After good conductivity is achieved between the injector and the producer, oil recovery is improved significantly.
This study aims to construct a hybrid CSS/SAGD simulation model for the Long Lake pilot well pad. The simulation is based on a well-defined 3D geostatistical model. By strictly controlling detailed lithological facies, lean zones and top water zones are accurately described in the geological model. These baffles are mainly located in the upper-middle portion of the McMurray Formation. By adjusting relative permeability curves, a SAGD model with a ten-year production history (beginning in April 2003) is history matched well. Based on this model, we then run hybrid CSS/SAGD simulations by changing well constraints from April 2003 with a submodel of well pair 1. Both wells in the well pair 1 operate as producers and injectors. The simulation results show that CSS-SAGD exhibits higher oil recovery and lower SOR than SAGD alone. Moreover, sensitivity analysis on preheating pressure is performed. Based on the net present value, we optimize the steam injection pressure and steam injection rate to establish criteria for each parameter for the pilot well pad.
This paper describes a numerical investigation of hydraulic fracturing in oil sands during cold water injection. Previous studies have shown that hydraulic fracturing in unconsolidated or weakly consolidated sandstone reservoirs is highly influenced by the low shear strength of these materials and is quite different from competent rocks. As such, existing classical hydraulic fracture models are incapable of predicting the fracturing process of weak sandstone reservoirs. This paper presents a numerical tool to simulate hydraulic fracturing in oil sands and weak sandstone reservoirs. A smeared fracture approach is adopted in the simulation of tensile and shear fracturing in oil sands. The model incorporates various phenomena expected in hydraulic fracturing, including poroelasticity and plasticity, matrix flow, shear and tensile fracturing and concomitant permeability enhancement, saturation-dependent permeability, stress dependent stiffness and gradual degradation of oil sands due to dilatant shear deformation and strain localization. The results of the hydraulic fracturing simulation indicate that poroelasticity as well as shear fracturing can result in breakdown and propagation pressures larger than the maximum in-situ stress. Applying such pressures in fracturing operations can compromise the caprock integrity. It is found that at injection pressures below the vertical stress, saturation-dependent relative permeability and the development of shear fractures in the reservoir highly influence the injection response.
Albardisi, Tareq (Schlumberger) | Akhmetov, Roustam (Schlumberger) | Sanderson, Martin (Schlumberger) | Adly, Essam (Schlumberger) | Escamilla, Barton (Schlumberger) | Andreasen, Greg (Schlumberger) | Noureldin, Ali (Schlumberger) | Al Habsy, Hilal (Schlumberger)
A heavy oil field, located in south-central Oman with unconsolidated sandstone reservoirs represents many drilling challenges. Past drilling with conventional mud motors in the field was associated with many drilling risks, including poor wellbore quality, difficulty steering, inadequate hole cleaning, and differential sticking. These risks resulted in extra correction trips, lost-in-hole bottomhole assemblies, sidetracking, and redrilling entire sections.
The field’s current development plan is based on the factory drilling concept, which is driven by the number of wells that are required to be delivered in a given year. This requirement places a great amount of importance on drilling time. The average time from spud to spud in the field is 8 to 9 days; any additional trips have a large impact on the total number of wells delivered. In addition, due to the nature of the heavy oil sandstone reservoir, steam injection is required to enhance oil recovery. It is therefore critical to place the lateral hole section of the well in the center of the target corridor to avoid early breakthrough. To compound this, the fluvial nature of the reservoir, tight surface location constraints, and shallow reservoir true vertical depths (TVDs) have added to directional complexity.
To address the main technical challenges of directional assurance and greater drilling efficiency, the operator and service company explored alternative ways of drilling the 8.5-in. reservoir hole section, and this hole section was be the focus of our analysis.
The learning curve experienced in finding an answer for the technical challenges of directional control and drilling efficiency can be broken down to four distinct phases:
Extensive data gathering and log analysis provided a better understanding of the main issues and ultimately led to the root cause. The analysis provided a clear solution, which was that a high-build-rate-capable RSS was needed to overcome the directional tendencies and deliver the planned well trajectory to the final total depth (TD) in one run to reduce the average well time.
Exploitation of heavy oil fields in Kuwait Oil Company (KOC) has been a challenging task. Both, cold and thermal methods are planned to produce these fields judiciously. Crude oil API gravity is 10-12. Well depth is from 700 to 3000 feet. Expected variation in production rate is from 30 - 300 bbl/d for cold production. With thermal application, envisaged range of liquid production rate is from 100 – 1000 bbl/d. Therefore, it is important to evaluate different artificial lift modes, to produce these heavy oil fields.
In this regard, application of various artificial lift modes, such as PCP, SRP, ESP, ESPCP, Metal PCP, etc., which can be used to produce heavy oil fields, under cold and/or thermal production pattern, are studied and are outlined in this paper.
With regard to this feasibility study, for cold heavy oil production, pilot of conventional PCP technology is carried out. Liquid rates of 30 - 300 bbl/d are achieved, when PCP technology, is tested for few wells, for cold heavy oil production. For heavy oil thermal production, pilot of ‘Metal PCP’ technology is carried out, with cyclic steam injection in place. Peak liquid production rate of 460 bbl/d is achieved, when metal PCP technology is tested in one well.
The paper describes pilot methodology of these pilots. Results of both these pilots are encouraging. This has resulted in planning to use both these technologies, to produce heavy oil fields, on large scale basis. Thus, the paper can be used as reference, to evaluate different lift technologies to produce heavy oil fields. It is inferred from the feasibility study that conventional PCP and metal PCP are emerged as desirable lift technologies, to produce heavy oil fields. Successful pilot implementation of these technologies, has further justified utility of these technologies, for exploitation of heavy oil fields.
The lack of an accurate reaction model for petroleum oxidation rates is a serious hindrance to the simulation of oil-recovery processes that involve air injection. However, the chemical literature on hydrocarbon oxidation contains many examples of possible reaction mechanisms that could serve as guides. These mechanisms were screened to identify generally accepted reaction paths that could help reveal how oxidation occurs in petroleum reservoirs.
It was found that there are at least seven groups of fundamental reactions that can seriously affect oxidation rates of crude oils. These seven reactions are as follows: two that lead to hydroperoxide formation; “branching” by hydroperoxides; two reactions governing the negative temperature coefficient region; oxidation inhibition; and at least one rate-controlling reaction at very high temperatures. Each of these groups exerts an influence within a separate, identifiable range of conditions. These reactions, and the conditions under which they become important, are outlined in this paper.
Various oxidation behaviours that have been reported for both light and heavy crude oils were then compared and aligned with the seven identified reactions. The result was a framework for selecting pseudoreactions that can facilitate the prediction of the oxidation kinetics under a wide range of oilfield conditions. Some of these pseudoreactions involve the direct representation of free radicals or other chemical intermediates, which is a departure from conventional practice for in-situ combustion simulation.
The new reaction framework is expected to serve as a reliable guide to the construction of predictive reaction models and, consequently, improved simulation of both in-situ combustion and high-pressure air injection processes.