Stuck pipe incidents and excessive torque and drag have been common problems encountered while drilling horizontal wells in the Orinoco Oil Belt which contains Venezuela's largest heavy oil reserves concentration. These incidents have been attributed mainly to high levels of friction between the drillstring and the heavy oil sands. To help prevent sticking, a common practice has been to add 10 to 20 vol% of diesel to the water-based fluid when drilling the horizontal sections. Open hole displacement of mud by diesel had also has been used to free stuck pipe. However, many of these incidents have resulted in the loss of the bottomhole assembly and the need to perform sidetrack operations.
Typically, engineered fluid solutions have been required to solve friction issues related to horizontal sections and tortuous well geometries. Additionally, a hydrocarbon-free and non-damaging lubricant option has been necessary to help prevent excessive torque and drag when drilling 2D and 3D well trajectories with a water-based fluid.
Recently, a viscoelastic drilling fluid comprised of a blend of special synthetic oils and surfactants has helped reduce the coefficient of friction in water-based mud by as much as 50% without adversely affecting the rheological properties, as well as dissolving bitumen and preventing emulsification of the heavy oil and sand. After the lubricant treatment, torque and drag values experienced while drilling highly deviated sections through unconsolidated sands at instantaneous penetration rates of up to 1,300 ft/hr have decreased from 18,000 to 12,000 lbf-ft. Also, because no stuck pipe incidents occurred and clean-up trips weren't required, considerable rig time was saved.
This paper discusses key aspects of the performance of the water-based, hydrocarbon-free, non-damaging lubricant used in drilling the Orinoco Oil Belt horizontal and multilateral wells, as well as the factors that enabled PDVSA to achieve project targets in a safe and timely manner and to minimize any detrimental environmental impact .
Problems with wellbore stability while drilling in shale have plagued the drilling industry for a long time. For good reason, the bulk of trouble-related problems while drilling have been in shales, and great expenditures in time and money are made each year dealing with the problem. However, shale interaction with drilling fluids in the drilling process remains a complex and often misunderstood area of study. By comparison, fewer wellbore stability problems occur while drilling with invert emulsion fluids (IEF) than when water-based drilling fluids are used. The theory of shale interaction with invert emulsions is briefly reviewed in this paper.
Actual measurements of changes in shale strength of two shales have been recently made using a new test device from the University of Oklahoma. Two very different shales were studied: one from a deepwater environment and the other a more-competent shale cored in a land-drilling operation. These shales were exposed to invert emulsions having different water phase salinities, and the stresses required to cause sample failure were measured under in-situ conditions. The results showed use of invert emulsions under some conditions weakened the shales, while under other conditions, the shales were strengthened. These results were then interpreted using current osmotic pressure and membrane efficiency theory of invert emulsions.
The results were compared to the elastic and porochemoelastic modeling using the rock mechanical properties determined in the laboratory testing. Using a set of drilling and wellbore in-situ stress conditions, traditional elastic wellbore stability modeling is used to predict the changes in tangential stress in the wellbore wall. Next, porochemoelastic modeling is used to predict changes in pore pressure as a function of time and of IEF water phase salinity (WPS). These results are then discussed in relation to the changes in shale strength seen in the laboratory.
Knowing that there are significant differences in rock strengths of shales exposed to invert emulsions having varying water phase activity levels, the drilling engineer can more effectively plan future wells, especially those having narrow safe drilling windows.
The definition of rock types (RT) and flow units (FU) in the static and dynamic models is useful to have a better description of the potential zones with a reservoir quality. The study and integration of information from conventional and special core analysis, well logs, test pressure, geocellular model, gridding and properties upscaling to simulation are required for the reservoir modeling characterization.
The Winland and Flow Zone Indicator (FZI) methods to identify RT, as well as, the Stratigraphic Modified Lorenz (SMLP) method for FU; are the most used techniques to determine the properties at the well level. This document describes a workflow of that techniques at well level to be applied to the 3D static and dynamic reservoir models. The main objective is to identify the different features of the RT and FU in the entire reservoir. As result of this methodology, the FU are well defined and are used to determine the zone mapping in the upscaling process to perform the reservoir simulation model; and put new wells with oil opportunities in a mature field.
A hybrid system of wind, solar, and diesel generators could provide an efficient alternative for powering water desalination projects in remote oilfield locations in Texas. Disposal of produced water from oil and gas wells is a costly procedure for production companies, but water-to-oil production ratios exceed 10:1 (by volume) at many wellsites. Much of the petroleum produced in the United States and elsewhere is found in arid regions that could benefit greatly if the produced water could be purified sufficiently for agricultural, industrial, or potable use. Our previous research identified and validated treatment options capable of recovering a high proportion of fresh water from oilfield brine. In this paper we further the earlier research by examining the possibility of using renewable energy to power the units in "off the power grid?? situations. A macro-driven spreadsheet was created to allow for quick and easy cost comparisons of renewable energy sources for a variety of scenarios. Using this tool, wind and solar costs were compared for cities in regions throughout Texas. The renewable energy resource showing the greatest potential was wind power, with the analysis showing that in windy regions such as the Texas Panhandle, wind-generated power costs are lower than those generated with diesel fuel.
Espadarte Field is located in Campos Basin at about 110 km offshore of Rio de Janeiro state, Brazil. The water depth ranges from 750 to 1,500 m and its ring fence has an area of 720 km2.
The Espadarte field exploitation strategy comprises 8 producers and 5 injectors and was developed using subsea vertical, deviated and horizontal wells, all they producing to the FPSO Espadarte. These wells produce from 4 oil reservoirs with maximum thickness of 53 m and saturated with 29° API oil and the production started in August 2000. Water injection started in 2001 and it is the main drive mechanism to replace the reservoir energy, having the field an active aquifer as well.In 2002, after the seawater breakthrough, a production decline was observed and Barium and Strontium Sulphates scale were detected. After that, the seawater injection was stopped in order to provide a Scale Control Plan, based on a remote inhibitor squeeze treatment.
During the seawater injection interruption, an intense production decline and pressure reduction in the reservoirs was observed. In 2005, the injection was resumed and improvements in production and reservoir pressure were observed immediately.
In 2007, a study to increase the seawater injection in the field was conducted to anticipate the production. From this study, several parameters were analyzed, including the reservoir fracture pressure, the capacities of water injection and treatment at the production facility, the wells injectivity index and the quality of injected water. These parameters are monitored by technical teams including reservoir, production operation and lifting & flow people.
This paper presents the methodologies adopted to increase the seawater injection in the Espadarte Field Module I. It is discussed the reservoir management and the results obtained with the reservoirs pressurization, namely production anticipation and stability of the process.
In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. A particular instance of transient flow in the near-wellbore region is the intermittent response of a reservoir that is typical of liquid loading in gas wells. Despite the high level of attention that the industry has devoted to the alleviation of liquid loading, the fundamental understanding of the associated phenomena is still surprisingly weak. This applies not only to the flows in the wells, but also to the ways in which these flows interact with those in the reservoir. The classical way of dealing with these interactions, inflow performance relationships (IPRs), relate the inflow from the reservoir to the pressure at the bottom of the well, which is related to the multiphase flow behavior in the tubing. These relationships are usually based on steady-state or pseudo steady-state assumptions.
However, such IPRs may be inadequate when a transition from an acceptable liquid loading regime to an unacceptable occurs over a relatively small range of production rates and, hence, over a relatively short time. The most satisfactory solution would be to couple a transient model for the reservoir to a transient model for the well. This paper presents the results of a numerical modeling effort focused on the identification of the transient pressure profile in the near-wellbore region during fully transient flow conditions. The preliminary results, obtained for a single-phase (gas) situation and for a three-phase (oil-water-gas) situation, show a "U-shaped?? pressure profile along the reservoir radius. The existence of a similar pressure profile could be the explanation for the reinjection of the heavier phase into the reservoir during liquid unloading in gas wells.
Viscosity is one of the gas properties that is always uncertain at high-pressure and high-temperature (HPHT) conditions because no reliable correlation has been developed for HPHT and accurate measurement of gas viscosities at HPHT is difficult. However, the industry currently does not pay sufficient attention to the need for accurate gas viscosity values in HPHT gas fields' development.
We show that small errors in gas viscosity affect the inflow performance relationship (IPR) curves and eventually change the reserves estimate for HPHT conditions in ways that can drastically influence production forecasting. A sensitivity analysis for a synthetic case at these conditions shows that a 1% error in gas viscosity measurement results in a 1% error in gas flowrate, which in a large scale of gas production may severely underestimate or overestimate recovery from an HPHT field. This linearity between gas viscosity and gas flowrate continues to ±10% errors.
An evaluation of gas viscosity correlations commonly used in the industry shows that none of them is reliable at HPHT conditions, mainly for two reasons: measured data are not available to confirm their consistency and they do not account for impurities in the gas.
Clearly, the industry needs accurate gas viscosity measurements and needs a new procedure to develop correlations based upon accurate HPHT gas viscosity data.
Lack of analogs and the nature of high mobility ratio waterflood conditions pose many difficulties for reliable performance forecasts for heavy oil waterflood. In many cases, although numerical simulation is the method of choice for forecasting, it also faces several challenges, including smaller grid sizes resulting in longer computation time.
In this study, we investigated streamline simulation (SL) as a potential method for heavy oil waterflood performance forecasting. Streamline is well known in the industry for its speed and its ability in minimizing numerical and grid orientation effects for light oil waterflood applications. Because heavy oil reservoirs generally have less free gas, small capillary and gravity forces, applications of the streamline simulation is promising. We used both mechanistic and field-scale models to delineate advantages and limitations of streamline simulations compared to the finite difference method (FD) for high mobility ratio waterflood.
First, we evaluated streamline simulation using 2D and 3D mechanistic models for the oil-water viscosity ratio range of 10 to 1000. The overall streamline results, in term of breakthrough time and oil recovery, are similar to that of FD, although some difference due to gravity treatment was observed. Further, streamline shows less grid orientation effects in homogeneous models. However, streamline method generates instabilities for viscosity ratios of 10 or higher that resulted in production profile oscillations. In addition, its results are sensitive to pressure update time step for viscosity ratios of 10 or higher, suggesting a sensitivity analysis of pressure updates needs to be done prior to a study.
Next, we applied the streamline method to a 3D heterogeneous segment of a heavy oil waterflood pilot project to verify the above observations. The model results confirmed the observations above. However, the streamline method does show computational advantage for large-scale field model with less frequent pressure update. Further, it also enhances the visualization of producer to injector connectivity.
When applied properly, streamline simulations can be a powerful tool for quick screening of heavy oil waterflood projects, estimating oil recovery, and water breakthrough time.
The Real option Valuation theory is based on the concepts of the options traded in stock markets applied to real projects, where those are considered options of investment. The methodology enables the valuation of a manager's flexibility to adapt and review his estimates for investment decisions if market or project's processes have any change. Real Option Valuation considers flexibility caused by uncertainties as a key point of an economic analysis of an investment.
This paper intends to develop a real option valuation model to be applied in investment opportunities where uncertainties related to the initial production rate and the decline rate are key variables, considering an exponential decline. We consider a scenario where we have an exploratory project with high levels of uncertainties regarding possible future production. Based on exploratory information about the field the company will decide if it will develop the reservoir or not. These uncertain variables are modeled by stochastic processes causing impact on the production of an oil field and in its economic returns as a result.
The model´s main idea is the definition of a decision-making rule including the valuation of the flexibility from the possibility of delaying an investment in an oil field due to better geological information. We used a continuous time real option model to estimate the option value and investment trigger point and compared the results to estimates from evaluation using traditional discounted cash flow economic analysis methodology.
The evaluation model is applied to a set of production curves based on real production data from a producing reservoir located in the Brazilian northeastern coast. Preliminary results show that the investment - rule is different from that of traditional NPV, that is, invest as long as NPV > 0. The methodology can be used as an additional economic analysis decision-making tool to help managers decide in an uncertain production environment. This model does not eliminate the traditional evaluation methodology.
One of the most important parameters calculated by reservoir engineers in a waterflood project is the variation of average water saturation with time to estimate the recovery factor. For years, this average water saturation after breakthrough has been obtained by finding the intersection of the tangent to the fractional-flow water saturation curve, fw vs. Sw, at fw = 1.0. However, this technique is subject to errors because it is difficult to determine the exact point where the tangent to the fractional flow curve intersects the curve.
This paper discusses the development of a new function that matches with all fractional flow calculations from relative permeability displacement data to oil-water viscosity ratios. This new function has four parameters that vary according to the mobility ratio. The advantage of this new function is that its derivative can be used to calculate the average saturation after breakthrough, giving more accurate results when estimating waterflood predictions and the volume of oil displaced. If we use this new function technique along with rock type distribution, assigning a relative permeability curve to each rock type, it is possible to evaluate the possibility a waterflooding project with high certainty.
We present the procedure for determining the four parameters of this new general function and the advantages of its application through field examples from reservoirs in literature and from reservoirs in Maracaibo Lake, Venezuela.