Orocual field is one of the largest growing onshore opportunities in North of Monagas basin, eastern Venezuela. The field is planning to increase its production potential to more than 500% in the next five years. Business plan involve new expansion opportunities with improving field economics. These opportunities include massive development of the shallow heavy oil horizons by steam injection and
development drilling in the deeper light and condensate reservoirs. To accomplish such a challenging goal, it was necessary to estimate new requirements for surface facilities while considering both reservoir uncertainties and multiple development scenarios.
This paper presents a unique and innovated method and a case-study for integrating multiple-reservoir forecasts with a surface facilities network, with economics and uncertainty. Subsurface responses from five Orocual formations were obtained from ten different reservoir simulation models with their associated well constraints. One single surface network model was used to gather production information from all the reservoirs and likewise was used to develop alternate production scenarios. An automated workflow handled the
integration of reservoir production uncertainty, drilling schedule compliance, workover success, economics and varying surface facilities capacities.
The procedure that we have developed in this effort permitted the visualization of a more realistic asset performance compared to requirements in the long-term. The procedure also identified future needs for artificial lift.
The methodology developed also served as a platform for the exhaustive optimization of wellbore and surface equipment sizing in the presence of uncertainties based on front-endloading (FEL) methodology. The procedure allowed the evaluation of parameters that affect uncertainty in well productivity, drilling schedule compliance, workover success, and varying surface facilities capacities, such as project
execution time, workover success, facilities uptime, and facilities spare capacity.
Field production profiles often deviate from simulated ones. Multi-disciplinary field study is traditionally a sequential process; decisions are often broken down and disconnected. Often, reservoir engineers just model reservoir response up to the bottom-hole, production engineers model the whole wellbore up to the well-head, and process engineers model the surface facilities from the wellhead to the tank [Saputelli et al., 2002]. In general, most parties assume constant pressures at the boundaries throughout simulation period.
During field development, not all subsurface uncertainties are considered for evaluating all feasible surface scenarios. Changes in well productivity, water-front advance, free-gas production, and fluid composition will affect both reservoir and surface response. Because of the previous, surface facilities may remain sub-utilized, reservoir potential may not be obtained, and field economics may not be achieved at peak performance.
PDVSA has implemented a planning methodology for selecting the optimal field exploitation strategy called MIAS (sustainable integrated asset modeling) [Acosta et al., 2005; Khan et al., 2006]. MIAS Orocual project's objective is to assure optimal short-term field operating strategies in agreement with long-term reservoir management objectives with social and environmental responsibility. Before the
project began, MIAS Orocual project required the readiness of a platform [Rodriguez et al., 2006] for the quantification of subsurface, wells, and surface uncertainty variables and the evaluation of the effect on the value creation.
An automated workflow for integrating multiple numerical reservoir simulated production profiles within one surface facilities network was developed and is presented in this paper.
Dou, Hong'en (RIPED,PetroChina) | Chang, Yu Wen (Research Inst. Petr. Expl/Dev) | Yu, Jun (Liaohe Oilfield E&D Research Inst.) | Wang, Xiaolin (RIPED,PetroChina) | Chen, Changchun (China U. of Petroleum) | Ma, Yingwei
This paper presents a new mathematic model to calculate heated reservoir area based on the heat balance principle in order to determine the well spacing for thermal recovery. The calculation result of the new model was compared with the classical models of J.W Marx and R. H. Langenheim (Petroleum Transactions, AIME Vol. 216, pp. 312-315, 1959), B. T Willman (JPT, July 1961, pp. 681-696), and Farouq. Ali (1970), using data from Liaohe heavy crude oilfield, China. The results showed that the new model is more accordable with oilfield actual condition than the three classical models. Also, this research reveals a new theory on huff ‘n' puff, which is that the heated radius of the heated region is expanded from the first cycle to the fourth cycle of huff ‘n' puff; in this case, the heated front was expanded with the increase of cycle. However, subsequent cycles (from fifth cycle to tenth cycle of huff ‘n' puff) repeat the heating of the previous heated areas, and the expanding heated area of the next cycle is smaller than the last cycle, and the new heating region should hardly be expanded after the 10th cycle. The authors point out the development results of heavy oil, extra heavy oil and super heavy oil deteriorate due to this reason. In addition, the authors emphasize that the traditional huff ‘n' puff for producing heavy oil, especially for extra-heavy oil and super-heavy oil has to be changed using new technique methods after the fourth cycle. Finally, a suitable well spacing for thermal recovery with huff ‘n' puff was obtained. The new theory was proved by heavy crude/extra heavy oilfield development.
Huff ‘n' puff has been used in heavy oil reservoir development since the 1960's. Heavy oil production techniques have been advanced greatly in Canada and Venezuela. In the early 1980s, many thermal recovery techniques were developed, such as insulation tubing, high temperature packer and measurement instrument of thermal parameters. In Liaohe oilfield, China; the reservoirs are at depth from 800 to 2000 m. Heavy oil development was a great success, with production rate reached 700×104 tons per year. During the 25-year production period (1980 to 2005), 20 % of the oil in place was produced. The mechanism of production was a combination of solution gas expansion and huff ‘n' puff, as the cycle of huff ‘n' puff is more and more, the development result become worse and worse. Currently, huff 'n ‘puff has exceeded 15 cycles in some wells. The adjustment of oil development strategy faces great challenges, especially in planning well spacing for different types of reservoirs in the oilfield to reach the maximum thermal recovery. The heating front of steam injection, swept region of hot water and the determination of the heated radius are the main parameters to be taken account for designing the well spacing of the heavy oil reservoirs during huff ‘n' puff. Well spacing for thermal recovery will not be determined if the heated radius should not be calculated accurately. Therefore, after the three classical models of J. W. Marx-R. H. Langenheim (1959), B. T Willman (1961) and Farouq. Ali (1970) was analyzed [1-3], and the paper presents three generalization calculation equations and a new model for calculating the heated radius of the thermal recovery.
Analysis of Classical Model
Many researches have developed the theory for the estimation of the heated radius of the heated region and design of well pattern by some scholars [4-8], and the three classical models of Marx-Langenheim (1959), Willman (1961) and Farouq Ali (1970) were used and introduced widely. However, the three models were not analyzed systematically, and the conclusions and recognizing of the heated radius of actual oilfield were not presented in past published papers. Also, the heated radius calculation of multi-cycle had not been revolved. Three generalization mathematics models of the heated radius with multi-cycle were given on the basis of the three classical models. Different performance characteristics of heavy oil, extra heavy oil and super heavy oil are analyzed by means of the three generalized mathematical models and actual oil field data.
Ramirez-Garnica, Marco Antonio (Inst. Mexicano del Petroleo) | Mamora, Daulat Debataraja (Texas A&M University) | Nares, Ruben (Instituto Mexicano del Petroleo) | Schacht-Hernandez, Persi (Inst. Mexicano del Petroleo) | Mohammad, Ahmad A.A. (Instituto Mexicano del Petroleo) | Cabrera, Maria
In this research a catalyst was evaluated in a combustion tube using heavy oil from Gulf of Mexico. The underlying objective is to increase the mobility of the oil inside the reservoir by effect of the catalyst during the combustion.
The catalyst, used in the experiments was previously mixed with heavy crude oil of 12.5 °API. The catalyst, in liquid phase, is based in Molybdenum, Cobalt, Nickel and Iron. This organometallic catalyst is highly soluble and ultradispersed, and it was mixture with heavy crude oil with a concentration of 750 ppm wt.
The porous media used in the combustion tube was a triturated dolomite carbonated rock with a 41.9% of porosity, and a particle size of 0.42 mm. This rock was used for two experiments at the same saturation conditions: heavy crude oil (23.79%), and water (25.26%).
The results obtained shown the advantages of use of catalyst in relationship of a conventional combustion as follows: (1) oil production increases, (2) faster combustion front, (3) higher efficiency in the combustion, and (4) higher temperatures at the beginning of the combustion.
The use of this kind of organometallic catalyst at low concentrations is a potential application in order to upgrade the oil properties in-situ, saving the cost of facilities on surface required for the same purpose.
Exploitation of reservoirs in the world is steadely moving inexorably towards large reserves of heavy crude oil. Producing, transporting and marketing this heavy oil represents a lot of problems, including almost inability of most refineries to accept heavy crude oils. Heavy crude oils could be more accceptable if they can be upgraded prior to send it to refineries. One of the techniques in which heat is purposely introduced into an oil-bearing formation primarily to reduce oil viscosity is the process called in-situ combustion. However, there is the idea of combination of this process with the use of catalysts as alternative to upgrade the heavy oil prior to production and prior to reaching the surface stock tank, either in an oil-bearing reservoir, near a producing well, or in the producing wellbore: in-situ catalytic upgrading process.
Several experimental investigations have been considered studies of combustion front behavior in porous media with catalytic agents following different routes: Downhole physical separations such as steam distillation1, and deasphalting2-4, thermal conversion as v.gr. visbraking5,6, underground hydrogen7-12, hydrogen precursor injection13 and, in-situ combustion14,15.
It was reported previously that metallic additives increased fuel deposition, although the mechanism is not well understood16-19. Examples of comprehensive studies about enhancing the combustion process by addition of metallic salts have shown that for some crude oils there is a modification of the reaction kinetics in a favorable way: salts such as tin chloride or ferric nitrate, promote combustion of light oils, being that combustion more uniform and occurs at higher temperature. However, in another study was not possible to obtain a sustained combustion of light oil without the addition of metallic salts20.
There are more works reported on mechanistic studies about upgrading extra heavy crude oil, and even with heavy oil residues using hydrogen sources and the addition of metallic catalyst without consider any air injection in the process21-23.
This paper presents the results of the evaluation of paraffin control treatments applied in rod pumped wells in La Concepcion oilfield, located at the western of Venezuela and operated by Petrowayuu, which is a mature field with paraffin deposition problems.
Before the study, the only treatment applied on the wells to control paraffin deposition was hot watering. Because the average production rate of the wells was 30 BFPD, the application of high volume treatments, as hot watering, implied production deferral due to their low productivity index (around 0.09 BFPD/psi).
Paraffin dispersant cold batch was used as an alternative treatment. To assess the effectiveness of the paraffin control treatments and their optimal application frequencies, it was necessary to use scale coupons observation, flowline pressure monitoring, and dynamometer cards analysis.
It was found that paraffin dispersant cold batch treatment resulted to be the most cost-effective way to control the problem in all of the wells evaluated and the optimal batch treatment frequency was determined for each well. Moreover, most of the wells had been treated in a very low frequency. Besides this, it was demonstrated that circulation of high volume of hot water generated production deferral.
This enabled Petrowayuu to increase its earnings in approximately 500,000 U.S. $/yr, compared with hot watering costs, mainly because of production deferral reduction.
Over the years, paraffin deposition has been a constant problem in the rod pumped wells of La Concepcion field. This deposition has been observed during pulling jobs (Fig. 1) in which approximately 1.000 ft of tubing are plenty of solid paraffin. An analysis of the subsurface rod pump failure statistics, which included data from 2003 to 2005, revealed that paraffin deposition resulted to be the main cause of the failures (Fig. 2).
To control the problem, Petrowayuu had tried several methods such as, steam injection, magnetic devices, bacteria injection, hot oiling, and lately hot watering. All of the methods applied had resulted to be unefficient or non cost-effective.
As a result of this and based on the experience that A. Haudet had in Medanito, it was developed a methodology to determine the optimal paraffin control method and frequency for each well. This methodology combined the use of scale coupons observation, flowline pressure monitoring, and dynamometer cards analysis. Once the most cost-effective treatment was applied, production deferral due to hot water jobs was reduced to a minimum.
Methods of Paraffin Control
There are many literatures reporting methods of paraffin control[1,2], they can be divided into four categories: Mechanical, thermal, chemical, and combinations of those.
Mechanical methods basically include scrapers. On the other hand, thermal methods include steam injection, bottomhole heaters, and circulation of hot oil or hot water. In hot watering, heated water is pumped down the tubing or casing when there is no packer.
Chemical methods include solvents, wax crystal modifiers, and paraffin dispersants. Paraffin dispersants are surface-active agents that dissolve the paraffin deposited on the tubing wall. In cold batches, water provides the dispersing medium for the paraffin compounds while is carried out of the well.
In some cases, one method is not enough to control the problem itself, so it is necessary to combine them.
Methods of Paraffin Deposition Assessment
The methods of paraffin deposition assessment used in this study were dynamometer cards analysis, scale coupons observation, and flowline pressure monitoring.
Analysis of dynamometer card is the main diagnostic tool for rod pumped wells. Paraffin can cause an increase of the load on the polished rod, so a treatment that removes this deposition will cause a decrease on load.
Scale coupons are metal pieces with small holes that promote scale deposition; they are commonly used in water systems, and are inserted in the flow stream to simulate what happens in the inner walls of the lines. By observing an exposed coupon, valuable information can be provided regarding the effectiveness of an applied treatment (Fig. 3).
Nares, Hector Ruben (Inst. Mexicano del Petroleo) | Schachat, Persi (Instituto Mexicano del Petroleo) | Ramirez-Garnica, Marco Antonio (Inst. Mexicano del Petroleo) | Cabrera, Maria (Instituto Mexicano del Petroleo) | Noe-Valencia, Luz (Universidad La Salle)
In this paper are discussed the effects of some metallic oxides used to upgrade the heavy crude oil properties. The underlying objective is to increase the mobility of the oil in the reservoir by reducing viscosity and improving the oil quality using alumina supported transition metals and liquid phase transition metals catalysts (derived from either acetylacetonate or alkylhexanoate compounds), both homogeneously mixed with heavy crude oil. This heavy crude oil upgrading is based on the decrement of the asphaltenes, resins, and sulfur contents, and the increment of its API gravity, and strong reduction of viscosity.
In the present work the heavy crude oil from the Golf of Mexico was studied. The API gravity was increased from 12.5 to 21-26, the kinematics viscosity was decreased from 18,130 to 100-8 cSt (at 298 K), the asphaltene content was reduced from 26 to 7 wt%, the sulfur was removed in the range of 30 to 60 wt%, and the distillable fraction was increased between 20 to 30 wt%, and determinated by Simulated Distillation and True Boiling Point (TBP).
Heavy crude oil can be an enormous energy source when the suitable technology is used to its improvement in both cases aboveground and within reservoir. The extremely large reserves of the heavy, extra-heavy crude oil and bitumenes (5.6 trillions barrels) and the low cost are the main factors that make attractive as feedstock in the refining industry [1, 2]. On the other hand, the word-wide of the conventional crude oil reserves have been drastically diminished to 1.02 trillions barrels causing in some countries (México) that a great percentage of heavy crude oil (50 vol.%) is mixed with conventional crude oil and is used as feedstock to the atmospheric distillation [1, 2]. Although in the past, the easy processing of the conventional crude oil favored the production of distillates, currently the situation is changing quickly and it could be different in a short term because of the high demand of fuels oil that is why it will be necessary to process heavy and extra heavy crude oil.
Nowdays, some of the main problems that heavy crude oil presents are as follow: (1) the low mobility through the reservoir as a consequence of its high viscosity, which affects the wells productivity index, (2) the difficult transportation to the refineries and its high costs, and (3) the low processing capacity in the refineries. For these reasons is fundamental to enhance the heavy crude oil, both aboveground and underground. Talking about aboveground oil upgrading, several processes have been studied and applied in the industry to improve the bottom barrel conversion. Some of the main processes are carbon rejection (Thermal Processing, Delayed coking, Fluid coking, Flexicoking, and Visbreaking) [3-5]; hydrogen addition (Hydroprocessing, Fixed-bed as Hyvahl-F, Ebullating Bed as H-Oil and LC-Fining, and Slurry Phase) [6-9], and physical separation (Extractive Processes, FW Solvent Deasphalting, and Demex) [10-12]. All these processes are focused on converting the atmospheric and vacuum oil residues (511 K+) into more valuable products such as gasoline, middle distillates and Fluid Cracking Catalytic (FCC) feedstock. Nevertheless, the hydroconversion of heavy crude oil aboveground has been applied only at semi-industrial level because of: (1) the special design of either fractionation towers or topping columns, (2) the high investment due to great hydroprocessing volumes of heavy crude oil required in the refineries, and finally (3) the high hydrogen and catalysts consumption.
An interesting alternative to recover the heavy and extra-heavy crude oil is the down-hole catalytic upgrading. This alternative presents several advantages comparing with its aboveground counterpart such as: (1) an increase in the well productivity index, (2) a reduction in the lifting and transportation costs from the downstream to the refining center, (3) the production of more valuable products as a consequence of the decrement in viscosity values and in the resins, asphaltenes, sulfur, and metal contents, and (4) the application of environmentally accepted processes.
This paper discusses the recent patent application filed by EnCana Corporation on the use of air injection to improve the performance of steam assisted gravity drainage (SAGD).
EnCana's SAGD/Air Injection process employs standard SAGD well-pair infrastructure. It optimizes between the ability of steam to preheat the reservoir during SAGD and the superior (follow-up) oil displacement efficiency of in-situ combustion.
Operationally, air injection is initiated after thermal communication has been established between well-pairs with steam. One interesting feature of this operating strategy is that down-hole bulk separation of oil and gas occurs which facilitates (a) efficient monitoring and control of the combustion, (b) design of surface facilities, and (c) corrosion mitigation.
Laboratory combustion tube tests are presented that confirm the ability to initiate and sustain combustion, as well as mobilize residual oil saturation to steam, within a SAGD chamber. These experiments were initialized at oil saturations and conditions representative of those in a steam chamber. The residual oil saturations were determined from a full-hole core taken in the vicinity of a mature SAGD well-pair at Foster Creek.
Numerical simulations of post-SAGD air injection are presented that suggest the ability to displace and produce oil banks between well-pairs and that recovery factor can be increased up to 8% of the original oil-in-place over conventional SAGD.
The simulations show oil production rates and recovery factor are expected to increase with higher air injection rates. However, instantaneous air-oil ratios, which are indicative of operating costs, also increase. Thus there is an optimum continuous air injection rate that maximizes profitability. Simulations further indicate that it is possible to recycle flue gases in the injection stream without affecting oil recovery.
One of the mayor economical impacts in a Project of artificial lift system shift is the associated cost of energy moreover the maintenance and well intervention must be considered. These variables are reflected as addition on the final artificial lift cost selected.
This study was accomplished based on experience at the Teca and Nare fields operated by Omimex Colombia where an artificial lift system shift was performed from Rod Pump (RP) into Progressive Cavity Pump (PCP), achieving significant savings in well downtime and energy consumption at the same volume of production.
The strategy to develop this project started with the identification of well candidates where steam injection was not feasible then a change on the artificial lift system was proposed to a set of wells.
Also is highlighted the importance of the operational variables in long term at the moment to choose an artificial lift system.
The heavy oil reserves have increased more than twice as conventional reserves worldwide. Heavy oil has become in an important issued to the oil industry then and a concern to its best exploitation such technical as economical methods are considered.
Traditionally heavy oil exploitation considered Rod Pump (RP) as artificial lift system, exposing occasionally well downtime as sand stickings and rod failures with poorly designs.
Nowadays thankfully to the technological development an alternative for heavy oil exploitation is presented the Progressive Cavity Pump (PCP) which offers benefits as good heavy oil and high sand contents handling and low initial investment and maintenance cost.
This paper exposes a study of the main technical and economical issues considered for the artificial lift system shift from RP into PCP in Teca and Nare fields located at the Middle Valley of Magdalena river Basin in Colombia.
Considerations for the shift system
Since its initial exploitaion (early 80`s) in Teca and Nare fields, Rod Pump (RD) was implemented together with cyclic steam injection as EOR to produce an oil of 12 °API and 12000 cp viscosity within heavy oil pattern.
On 1st of April of 2004 in Omimex Colombia (operator of the fields) a project of well description started and were identified a set of wells no suitables for steam injection due to conditions as high water cut, completion problems like collapsed casings, liner ruptures and high sand content at wellbore as well as low injectability factor.
A trial of PCP system on well Teca 326 started on 10th of January of 2005 with promising results on operational consitions and steady production of 50 BPD compared with the former RD.
Based on these results arose the idea to install 75 PCP systems on the set of wells with non injectable factibility.
According to the production rate 20 to 60 BPD (32 wells), 60 to 100 BPD (25 wells) and 100 to 150 BPD (18 wells) of the set of wells, three differents systems of PCP were designed with power of 10, 20 and 30 HP to cover respectively.
While installation of the new systems and period after an evaluation process and comparison, of performance and economics was done between the two systems. The results gives the following conclusions.
Technical issues evaluated were flow and viscosous fluid handling and specially energy consumption.
Castanhal is an onshore heavy oil field located in Sergipe-Alagoas basin northest of Brazil. It is a shallow unconsolidated sandstone reservoir. It has 75 wells where the average reservoir depth is 350m. The oil has high viscosity ranging from 1000 cp to 9000 cp and API gravity ranging from 10° to 16° API.
In early eighties, a small steam injection project was started in the field, but due to operational problems it was interrupted few years later. In that time the oil low prices make the field be practically abandoned: The production was carried on by very few wells without any fluid injection. In 2003, some successful experiences with frac pack and horizontal wells lead to a renewed interest in the field.
Geological and numerical studies have been accomplished and a permanent temperature monitoring technology was selected to improve the reservoir knowledge and validate the studies.
Among the monitoring technologies available in the market DTS (Distributed Temperature Sensing) was selected. It
allows a complete wellbore-temperature profile in few minutes if needed. In this case four observetion wells were equipped with an optical fiber placed along the entire length of the well.
This paper will present a steamflooding pilot in a nine spot, with four temperature observation wells completed with frac
pack to avoid sand production and DTS to improve the understanding of steam breakthrough in the producer wells
and the steam path in the injection well. The information support better decision making to increase steam injection
Castanhal field was discovered in June/1967 by 1-CL-1-SE well. It is located in Brazil and lies on north of the Sergipe-Alagoas basin and It is 50km far from Aracaju city (Figure 1). Its reservoirs are fine-grained sandstones and conglomerates from the Carmopolis Member of the Muribeca Formation, with high permo-porosity, saturated with biodegradeable oil, high viscosity ranging from 1,000 to 9,000 cp and API gravity ranging from 10o API to16oAPI. The oil in place (OIP) is about 178x106 bbl (december/2006).
Figure 1: Castanhal field map location.
The field produced oil by cyclic steam stimulation (CSS) and steamflooding during 1990 year and due to lower Brent prices and high operational costs related to sand face control the steam injection project was abandoned2. In 2001 this situation changed by a well succeded frac pack project with equipaments suited for steam injection. A new steamflooding project in a nine spot was started in june/2006 but now adding distributed temperature monitoring in four observation wells.
The geological interpretation of the well logs in about 73 wells drilled allowed, with confidence, to map four pay zones
MUR/CPS-1, 2, 3 e 4. The Figure 2 shows a well log from Castanhal field with its four zones.
Operationally Castanhal field is divided in four sandstone zones, CPS-1, CPS-2, CPS-3 and CPS-4 with different
geological characteristics. Zone CPS-2 has the best lateral continuity followed by zones CPS-3, CPS-1 and CPS-4, where this last one is more affected by the presence of shales.
A three-parameter model relating the decline of the oil cut with the fractional oil recovery for waterflooded petroleum
fields or reservoirs is described. The model is based on observation of the behavior of several Brazilian oil fields, in which the oil displacement occurs either by water injection or by natural aquifer influx, or both.
The model is used to derive equations to forecast the oil and water production rates in waterflooded systems. These equations may also be used to design a waterflood expansion in any phase of a field's life.
An example of the application of the model equations to forecast the behavior of a waterflood in a mature heavy oil
field is presented. Because the results of the analysis indicated that the field will still be profitable at the end of the concession period, the model equations are applied to design and forecast an augmented waterflood for the field.
The model equation may be used to estimate the oil reserves at any stage of maturity of an oil field.
The model parameters are obtained by fitting the model equation to historical field data by means of a least square
algorithm. A type-curve procedure is applied to obtain the initial guesses of the model parameters required by the
A relation between the oil cut decline model and the classical rate-time decline is derived for the case in which the total
liquid flow rate is constant.
Examples of oil cut decline of several Brazilian fields are presented and the decline model is used to determine the
ultimate oil recoveries of these fields. The ultimate oil recovery is proportional to the amount of water produced
during the field's life, which is related to the water-oil ratio at abandonment conditions.
When the operating conditions of a field change, so does the oil-cut decline trend. An example of the change in the oil-cut decline trend is presented for a heavy oil field submitted to a late steam drive.
Water injection and natural water influx are very effective mechanisms to displace oil towards the production wells and
to maintain the reservoir pressure. Due to the nature of multiphase flow in porous media, such mechanisms always
lead to an increasing water-oil ratio in the producing wells. Forecasting both oil and water rates is of utmost importance
for the design and implementation of waterflood projects in the several phases of the field's life.
Historical data of oilfields show that it is possible to keep the oil throughput nearly constant for very long time by
continuously increasing the water injection rate. For instance, by keeping constant bottom-hole pressures in both producers and injectors wells, the increase in the liquid rate is natural in heavy oil fields, since the low mobility oil is displaced by the high mobility chasing water. Infill drilling also helps to increase the injection rate, and consequently the total liquid production, due to the increase in the reservoir pressure gradient. In both cases, there is an increase in the drainage velocity and, when the capillary and gravitational effects are small, the ultimate oil recovery will not be affected by increasing the drainage velocity. In this case the increase in the water injection rate anticipates the oil recovery.
Here we use simple methods to extrapolate the oil cut in order to forecast the capacity of the surface facilities required to handle the produced water, once a restriction in produced water rate leads to a decrease in the oil production rate.
In fields under water injection or water drive mechanisms, the water breakthrough occurs after a period of primary
production, where a given fraction of the initial oil in place is recovered. This period is followed by both a continuous
increase in the water-oil ratio and a continuous reduction in the oil cut.
Arps1 presented a hyperbolic equation to describe the decline of the oil rate with time. Such equation has shown to be ofrestricted use for waterflooded reservoirs, where an infill drilling campaign can even cause an increase in the oil rate.
However, even in this scenario the oil cut always decline.
The objective of this study is to investigate the advantages of drilling horizontal wells on oil recovery improvement. To evaluate the effect of horizontal length, porosity, anisotropy, staggeredline well pattern with gas injection (in the top layer) and water injection (in the bottom layer), different scenarios were studied.
This study is focused on simulation of formation-A of a carbonate reservoir which consists of three layers; where horizontal well is going to be drilled in layer-2 of this formation. The average thickness of formation-A is about 167.64 meters (550 feet) and we also have tilted water oil contact in this formation.
This field has produced around 146.9 MMBBL until year 2002 for the last 12 years with the Recoverable Reserve of about 237.31 MMBBL. Up to now 40 wells have been drilled in this field.
IRAP/RMS software was used to generate geological model. Based on selected reservoir black-oil model, IMEX from CMG is used for
simulation task. Sector model used for simulation as we only had one productive horizontal well in the formation (scale-down method).
This study confirms simultaneous use of overbalance method and horizontal well in this reservoir in order to: A) Increase production rate up to 3 to 4.5 times by boosting productivity index (PI). B) Communicate a large area leading to a better drainage area. C) Postpone the water breakthrough by minimizing the draw down pressure.
To identify the key factors controlling the impact of drilling new horizontal well at the reservoir scale are always a fundamental issue. Once this identification is done, simulation model will allow determination of which combination of vertical and horizontal wells will be the most suitable drilling activity in order to enhance the production. The impact of a horizontal well on the reservoir will depend on many factors. This includes the number of existing wells, well spacing, formation thickness, Kv/Kh, type of drive mechanism, completion
intervals of vertical wells, well radius, drainage radius, oil viscosity (and other PVT properties) and obviously the length and placement of horizontal wells. The aim of this study is to assess effect of horizontal well performance on boosting oil recovery. A case study from one of Iranian reservoirs is simulated.