This paper describes the technical and legal problems have had in the design and construction of several projects in the oil and gas industry in Mexico and propose a methodology in order to avoid that.
Traditionally the people in charge of the projects have been people with a lot of experience in different areas of the company but the knowledge in legal and technical aspects of the projects is limited. These last two aspects are the key in the solution of the common problems.
The proposed methodology is based on the experience through 18 years in the design and construction of several oil and gas installations and it is complemented with the analysis of legal and technical regulations.
Traditionally the design and construction projects are taken for a single person who is in charge of all aspects of the project since conceptual engineering until the tests and start up of the plants this way to do the projects brings a lot problems due to a bottleneck in the definitions of the main aspects of the projects which depend on the leader of the project who has a lot of experience in several aspects of the technical area or administrative area so normally the leader can solve the problems related with his experience but normally there are a lot of aspects that require definition in time and form for the correct development of the project and the background of the leader is not enough to solve them and unfortunately the main team do not have the knowledge and experience to solve them so the problems will accumulate until someone take the decision in order to continue with the project (Fig. 1).
This traditional way to do the projects has a lot of opportunity areas such as:
Bottleneck in taking decisions
Delaying of engineering works
Delaying in construction program
Increase in engineering costs
Increase in construction costs
Deviation of original objectives
Additional projects for solution
Increase in total cost of the project
Deviations from the mid and long term plans
Legal problems for the people
Life Cycle of the Project
The different steps of the project involve several disciplines since needs detection until site remediation (Fig. 2) each one has particular importance in according with the objectives of the department involved but at the end the main responsibilities fall over the engineering and construction department due to this department must understand the planning objectives and must to know the strength and weakness of the operation and maintenance department in order to give the best solution for the project. If there is some misunderstand this can cause problems on the project execution and break all the planning programs. In order to avoid that is necessary to adopt a new way to do the projects and one of the main changes is to do Performance Contract for each one of the people that will participate in the project, which let him to know and understand the objectives in the short. Middle and long term and in case of deviations be able to take the correct solutions in form and time in this way the relation inside the asset must be clear for the people (Fig. 3) The premises to get it are:
Working to Known Standards
It is proposed a simple methodology to secure the satisfactory ending of the project, it is divided in two main areas: Technical and legal.
We present in this paper a reservoir analysis of the application of multilateral well technology in single-target structures. We focus on the correspondence between reservoir type and established multilateral well technologies. We consider a wide range of permeability fields and fluid characteristics, but consider only the depletion or solution-gas drive mechanism. We suggest that the behavior of multilateral wells under other drive mechanisms is fundamentally similar to that under the solution gas-drive mechanism. We conclude that with respect to the application of multilateral well technology, where the objective is attaining favorable production performance, there are essentially two classes of reservoirs - those that require maximum exposure to the wellbore and those that require limited exposure. The traditional unsealed multilateral technology (levels 1-4) is appropriate for the first class, while the recent sealed junction technology (levels 5-6) is appropriate for the second class. We explain precisely why that is so, and what criteria can be used to select the appropriate multilateral level within each reservoir class. We substantiate our conclusion by benchmarking the performance of multilateral wells with horizontal wells. Also we note that the correspondence between reservoir and multilateral technology types seems consistent with the economic feasibility of these solutions.
The successful implementation of horizontal drilling over the last two decades has led to the development of multilateral well technology. The number of multilateral well completions has increased substantially in the last several years due to advances in directional drilling and completions systems.1 Many field applications have been reported in the literature including compartmentalized reservoirs in UK2and Malaysia,3 stacked dual and triple, and fishbone laterals in Venezuela,4-5 and diverse applications in onshore and offshore USA and North Sea,6 Thailand and Brunei,7 Canada, Brazil, Italy,8 Nigeria,9 and the Middle East.10
The key driver in the application of multilateral technology has been exploitation of multi-target structures. These include compartmentalized, layered, and dispersed structures. The result is field development with fewer wells. On a per well basis this appears as accelerated production. The trade-off is reduced flexibility in reconciling production from potentially incongruous formations. Also, there may be greater risks in well failure due to unfavorable geomechanics.11-12
Application of multilateral technology in single-target structures has been thus far limited to naturally fractured reservoirs and heavy oil deposits. However, with the increasing number of subsea and deepwater developments, this technology is poised to become a common means for producing single-target structures, irrespective of crude type or other characteristics.
The objective of this study is to provide a firm foundation for this emerging class of applications. We take note of the latest developments in modeling wells of complex geometry13-16 and use recent numerical methods adapted to modeling these configurations.17-18
The previous studies incorporating the matrix-fracture transfer functions in the naturally fractured reservoir models overlooked the effect of the fracture surface conditions on primary petroleum recovery by pressure depletion and secondary oil recovery by waterflooding and capillary imbibition. This paper presents an improved matrix-fracture transfer model and analytical solutions for rectangular shape matrix blocks in naturally fractured petroleum reservoirs by hindered interface flow between matrix blocks and surrounding fractures. The rectangular shapes are considered to represent the matrix blocks formed by intersecting fractures. The restricted and hindered matrix-fracture interface flow phenomenon is considered in order to account for the effect of the skin due to damaged matrix block surfaces by various processes, including deposition of mineral matter and other debris. The matrix fluid flow equations are formulated for multi-dimensional media, and linearized and solved analytically. The formulation is carried out in dimensionless form, leading to the same dimensionless equations and results based on the analogy between the single and two-phase flow situations involving pressure depletion and capillary-imbibition induced petroleum recovery processes. Then, full scale, and short and long-term analytical solutions are presented and validated by experimental data.
By means of these analytical models, various laboratory experimental data are analyzed, and it is demonstrated that the condition of the matrix block surface is an important factor in determining the rate of fluid flow between matrix blocks and fractures, and the skin effect may reduce the petroleum recovery factor. Comparison with previous simplified models shows that the present model can accurately predict the matrix-fracture interface fluid transfer rate over the full range of the petroleum recovery period, while the previous models can only represent either the early or the late time behavior with limited accuracy. In addition, the effect of the reservoir rock properties on the rate of petroleum recovery by hindered-flow is investigated by means of the hydraulic diffusivity coefficient, determined by correlating the experimental data by means of the new models. This study reveals that there is a strong relationship between the petroleum recovery factor and the diffusion coefficient.
The analytical models developed here can be utilized for rapid and accurate prediction of gas recovery from naturally fractured reservoirs undergoing a pressure depletion or waterflooding process.
The Spraberry and Chicontepec fields are both giant oil fields contained within areally extensive, low porosity and low permeability submarine fan reservoirs. Each field has a gross interval of approximately 1,000-1,500 feet (300-450 m) with multiple reservoirs less than 10,000 feet (3,000 m) deep. Sand-prone intervals are laterally extensive and can be correlated regionally, but do have localized channeling. Both fields produce from solution-gas drive.
The Spraberry Trend Field, located in the Midland Basin of West Texas, was discovered in 1948. The field is estimated to contain over 10 billion barrels of original oil in place in a series of stacked Permian-age reservoirs covering over 2,500 square miles (6,475 sq. km). Cumulative production from the Spraberry is approximately 850 million barrels of oil and 3 trillion cubic feet of gas or approximately 8% of the original oil in place.
The Chicontepec Field, located in the Sierra Madre Oriental foothills in east-central Mexico, was first drilled in 1931. The field is estimated to contain 140 billion barrels of original oil in place and 35 trillion cubic feet of associated gas in a series of stacked Late Paleocene to Eocene-age reservoirs covering approximately 1,440 square miles (3,731 sq. km). Cumulative production from the Chicontepec Field is just over 140 million barrels of oil-equivalent or 0.1% of the original hydrocarbons in place.
However, the fields do differ significantly in their development history. Over 18,000 wells have produced some oil and gas from the Spraberry (over 10,000 currently producing) as compared to less than 1,000 in Chicontepec. Managing drilling costs, fracturing technology and controlling production costs along with economies of scale have allowed the Spraberry, once known as the world's largest uneconomic field, to be developed. Developing the Chicontepec field using similar methods would add significant reserves and production volumes for Mexico.
As we all know, finding new giant accumulations of oil and gas through exploration, especially in areas close to markets and existing infrastructure, is becoming increasingly difficult. An alternative is to look at previously discovered fields in these "mature" areas that are underdeveloped because of their historically low margin economics. Often through the use of new technology and by creative cost-cutting methods significant new production and reserves can be developed to more quickly meet consumer demand even without higher commodity prices.
This paper is a high-level comparison of two such fields; discussing the reservoir properties which have caused them to be deemed "uneconomic" and contrasting the development histories to suggest significant new reserves can be economically produced near-term from one that is underdeveloped.
The two fields are the Spraberry Trend Field located in the Midland Basin in West Texas and the Chicontepec Field located in east-central Mexico (Fig. 1). Both are located in mature producing regions where numerous other fields, including fields with significantly less original hydrocarbon in place, but with better reservoirs, have produced millions of barrels of oil and billions of cubic feet of gas.
As development of hydrocarbon reserves continues to move into deeper and more complex reservoir conditions, operators have found that conventional techniques for testing, perforating, and stimulating have not been capable of providing satisfactory results in the severe well conditions. Even if operationally satisfactory, they have been unable to meet the goals for cost efficiency.
This paper describes an experience in the Tropical Field, located in eastern Venezuela and operated by Repsol - YPF in which the reservoir is characterized by high-pressure reservoirs and complex geology due to faults and high-dip-angle formations. Repsol needed a method that would optimize well testing operations, improve safety, and cut costs without compromising the results of the operation; thus, a major change to traditional drill stem testing operations was needed. A technique, which would eliminate the need to kill the well to retrieve the guns and also provide the flexibility to test, evaluate, and fracture the well, was suggested. Instead of using a drilling rig or a work-over unit as in the standard drill- stem testing operation, the procedure would allow the operator to perform a rigless well test evaluation using optimum underbalanced conditions in favor of the reservoir.
Several alternatives were evaluated for perforating and testing the well. After thorough examination of all possibilities, snubbing- and coiled-tubing-conveyed perforating (CTCP) methods were selected as the most promising alternatives for achieving the objectives proposed at the beginning of the project. While coiled tubing had been used to perforate in other areas in Venezuela, coiled tubing combined with snubbing had not been used in Venezuela.
This paper will focus on the methods developed to satisfy the operational challenges, the results obtained with the use of the newly applied technologies, and how the technology was able to address the operator's needs as well as the difficult reservoir conditions. Instrumental in the success of the methodology was the combined use of super-deep penetration technology, state-of-the-art memory tools for depth correlation, real time data transmission, and the flexibility to perform several operations during a rigless well-test evaluation. This case history represents the first live-well intervention using snubbing and coiled-tubing perforating techniques performed successfully in eastern Venezuela.
The Tropical Field is located in east Venezuela approximately 28 miles from Maturin, capitol of Monagas state, in the North Monagas Area. This location is one of the most prolific production areas in the country. The reservoir is characterized by high-pressure and complex geology due to faults and high-dip-angle formations. The field is presently under development, and 4 wells have been drilled. Oil is produced from two locations - the San Juan Formation at approximately 13,890 feet and from the San Antonio Formation at approximately 14870 feet. The average total depths in the wells are 15,800 ft. and are slightly deviated. Thus, perforation techniques had to be capable of operating in complex geology due to faults and high-dip-angle formations.
Perforating Techniques used on Tropical Area.
During the exploratory stage of field development, tubing-conveyed perforating (TCP) was used since it offered the capability to perforate the well in an underbalanced condition. In the first wells, the TCP string included the DST string for evaluation. The wells still had to be killed, but underbalance was obtained. Then, rigless perforating systems were considered. The objective of this change was to optimize the cost involved during the well-testing evaluation operation, and at the same time, obtain the benefits that can be achieved from having the completion already in place and the capability to perforate without killing the well.
The technology applied at the beginning of the project was to perform TCP on coiled tubing; however in the well discussed in this case history, it also became necessary to use a snubbing unit to perform the gun runs because of the difficulties experienced in meeting operational requirements in the complex geology.
4D seismic technology is becoming routinely incorporated in reservoir management by some of the majors—to improve reservoir characterization for EOR, identify unswept oil, GOC, hydraulic communication, infill well locations. To estimate changes in seismic properties due to production, generating the reservoir's theoretical seismic response is indispensable—for guiding interpretation and quantification in terms of saturation and pressure change.
Simulating the reservoir's seismic response to potential rock and fluid distributions is essential for relating 4D seismic information to production—especially for inverting seismic information to an estimate of acoustic impedance change and Poisson's Ratio change. The choice between 1D-, 2D-, 3D-raytrace or full elastic seismic simulation depends on the structural complexity of the reservoir and overburden, the reservoir's elastic profile, and the potential artifacts from differences in the seismic acquisition & processing parameters.
Given the potential pitfalls and limitations of both modeling and data, it is necessary to visually relate geologic, engineering and geophysical information (shared-earth-modeling) to guide the quantification of seismic information for reservoir model updating and history matching. Relating different data types measured at different scales requires a case dependent development of rock physics transforms and downscaling methodologies for updating the high-resolution geologic model with results from the flow-simulator.
To illustrate the above in the context of potential impact on reservoir management, three examples are shown:
Deepwater Brazil water-injected oil field with evolving critical gas: 4D seismic analysis of two 3D surveys; utilizing 1D and 3D raytrace modeling.
North Sea gas-injected oil producing field: 4D seismic analysis of three 3D seismic surveys acquired during 8 producing years; utilizing 1D seismic modeling.
North Sea reservoir: synthetic AVO time-lapse seismic study comparing 2D raytrace and 2D HybriSeis (raytracing above reservoir, full elastic modeling of reservoir).
This paper presents a methodology for the optimal hydraulic fracture treatment design. The methodology includes, the construction of a "fast surrogate" of an objective function whose evaluation involves the execution of a time-consuming computational model, based on neural networks, DACE modeling, and adaptive sampling. Using adaptive sampling, promising areas are searched considering the information provided by the surrogate model and the expected value of the errors.
The proposed methodology provides a global optimization method, hence avoiding the potential problem of convergence to a local minimum in the objective function exhibited by the commonly Gauss-Newton methods. Furthermore, it exhibits an affordable computational cost, is amenable to parallel processing, and is expected to outperform other general purpose global optimization methods such as, simulated annealing, and genetic algorithms.
The methodology is evaluated using two case studies corresponding to formations differing in rock and fluid properties, and geometry parameters. From the results, it is concluded that the methodology can be used effectively and efficiently for the optimal design of hydraulic fracture treatments.
Hydraulic fracturing is one of the most common stimulation strategies used to enhance the production from oil and gas wells. During a hydraulic fracturing treatment, fluids are injected to the formation at a pressure high enough to cause tensile failure of the rock, and propagate the fracture. As a result of a successful treatment, a path with much higher permeability than the surrounding formation is created from the well. Each of the fluids injected during the treatment execution performs a significant and specific task. The initial fluid, known as pad, initiates and propagates the fracture. The following stages of the treatment involve the injection of a fracturing fluid with varying concentrations of proppant. The fluid is intended to continue the fracture propagation and the proppant will keep the fracture open, even though the formation stresses will try to close the fracture, after the fluid injection ceases.
For a given formation, the design of a hydraulic fracture treatment involves the selection of appropriate fracturing fluids and proppants, the number of treatment stages, the concentrations and the rates and pressures of injection of each stage. Each design will result in a specific fracture geometry and conductivity, which is related to the production increase obtained from the fractured well. This means that, due to the several possible combinations of the parameters involved, and their non-linear interactions, there are a significant number of possible fracture geometries, each of which will result in a different post-fracture well production performance.
Ralph and Veatch1 presents the general concepts of hydraulic fracture treatments economics and introduced the net present value as a valuable tool for the optimal design of hydraulic fracture treatment. An optimal hydraulic fracture treatment design maximizes the net present value of the revenue after the treatment, considering the post-fracture production performance and the treatment costs.
It is generally accepted that the success of underbalanced drilling (UBD) operations is dependent on maintaining the wellbore pressure between boundaries determined by the formation pressure, wellbore stability, and the flow capacity of the surface equipment. Therefore, the ability to accurately predict wellbore pressure is critically important for both designing the UBD operation and predicting the effect of changes in the actual operation. Most of the pressure prediction approaches used in current practice for UBD are based on empirical correlations, which frequently fail to accurately predict the wellbore pressure. Consequently, the current trend is toward increasing use of prediction methods based on phenomenological or mechanistic models.
This paper presents an improved, comprehensive, mechanistic model for pressure predictions throughout a well during UBD operations. The comprehensive model is composed of a set of state-of-the-art mechanistic steady-state models for predicting flow patterns and calculating pressure and two-phase flow parameters in bubble, dispersed bubble, and slug flow. In contrast to other mechanistic methods developed for UBD operations, the present model takes into account the entire flowpath including downward two-phase flow through the drill string, two-phase flow through the bit nozzles, and upward two-phase flow through the annulus. Additionally, more rigorous, analytical modifications to the previous mechanistic models for UBD give improved wellbore pressure predictions for steady state flow conditions. The results of using the new, comprehensive model were validated against two real wellbore configurations with different flow areas. Field data from a Mexican well, drilled with the simultaneous injection of nitrogen and a non-Newtonian fluid and full-scale experimental data from the literature validate the improved model predictions. Additionally, a comparison of the model results against two commercial UBD simulators, which rely on empirical correlations, confirm the expectation that mechanistic models perform better in predicting two phase flow parameters in UBD operations.
Because of the complex nature of the hydraulic system of UBD operations in which two or more phases (liquid, gas, and solids) commonly flow, the prediction of pressure drop and flow parameters such as liquid holdup and in-situ liquid and gas velocities are mainly performed using empirical two-phase flow methods. The Beggs and Brill1 correlation is the most popular among the current commercial UBD simulators. However, it is recognized by the petroleum industry that most of these empirical correlations were developed from large experimental databases, thereby making extrapolation hazardous2. Moreover, the Beggs and Brill1 correlation has been shown to over predict or fail to predict bottom hole pressures for both vertical or horizontal UBD operations3,4.
Since the mid 1970's, significant progress has been made in understanding the physics of two-phase flow in pipes and production systems. This progress has resulted in several two-phase flow mechanistic models to simulate pipelines and wells under steady state as well as transient conditions. Consequently, mechanistic models, rather than empirical correlations, are being used with increasing frequency for design of multiphase production systems. Based on this trend of improvement, the application of mechanistic models to predict wellbore pressure and two-phase flow parameters seems to be the solution to increase the success of UBD operations by improving such predictions.
Bijleveld et al5 developed a steady state UBD program to assist well engineers in planning and executing underbalanced operations. This in-house computer program uses the mechanistic two-phase flow approach. However, there is almost no technical information in the literature about the implementation of the mechanistic models in UBD operations.
We present results of modeling studies of injection schemes with wells using new completions technology, and address how these are applied or envisaged for the fulfillment of field development strategies in offshore environments.
A common theme in offshore developments is the use of fewer wells to achieve the production targets of the field. In mature fields, the limited availability of well slots is a severe constraint. In new developments, the drive is towards fewer and smaller platform installations. In subsea developments, particularly in deepwater, the objective is minimization of wellheads. There are clear financial, environmental, and technical reasons for these trends.
The use of advanced completions technology to reduce well requirements has been widely practiced in relation to production wells. Commingling of production in layered, compartmentalized, and dispersed geological settings has been achieved with multilateral wells, and conventional wells with flow control technology.1-4 The application of this technology to injection problems has received relatively little attention.5-6
The objective of this study is to analyze a number of injection problems that arise from actual field development scenarios. Four cases will be presented. The first two concern achieving proper partitioning of injected water into multi-zone structures. The third case concerns achieving the total target injection rate and partitioning. The fourth case concerns the alternating injection of water and gas.
This is a deepwater field, being developed by subsea wells. The structure consists of two partially overlapping formations of high permeability (3-5 Darcies), separated by non-reservoir rock. There is no external drive mechanism in the reservoir (e.g. an aquifer). Injection is to commence at initial production. Vertical injectors completed in both formations are to be used. The lower formation has about 1.5 times the injectivity of the upper formation because of its larger effective thickness. The objective is to inject into the upper and lower formations with a split of about 45% and 55% respectively, in line with the estimated distribution of reserves. The operator plans to install fixed and/or variable flow control devices in the injectors. The study analyzed injection options with and without valves. As Figure 1 shows, when no valves are used, the water will spontaneously partition between the two zones in the ratio of about 20% into the upper zone and 80% into the lower zone at relatively low injection rates. As the injection rate increases, so does the frictional pressure loss and this changes the ratio between the upper and lower zones to about 35% and 65%. This is shown in Figure 2. Note, however, that the fracture gradient of the formation imposes a constraint on the injection rate. Figure 3 shows that the desired partitioning can be achieved when both formations are equipped with variable flow control valves. By adjusting the valve apertures, the partitioning of the injectivity can be adjusted as reservoir conditions evolve.
This example concerns injection into three zones simultaneously, prompted by the limited number of well slots available on the platform from which this reservoir is being developed. In comparison to the previous example, there is greater contrast in the reservoir properties among the three zones, so that the middle zone has the highest injectivity index. The operator has initiated a water injection program for pressure maintenance, using vertical dual-string injection wells (two tubing strings), with the short string injecting into Zone A and the long string into Zones B and C. With this configuration, the approximate partitioning in injectivity is 25%, 50%, and 25% (Figure 4).
Several factors, including the oil composition, reservoir pressure and temperature, and the properties of asphaltene, influence asphaltene precipitation from reservoir oil. Asphaltene starts to precipitate and plug the reservoir pore space under certain reservoir conditions, reducing flow capacity of the wells and the amount of recoverable oil. It is necessary to understand the mechanism of asphaltene precipitation and the resulting effects on well performance in order to build a representative forecasting model for reservoir management. The goal of this study is to model the effects of asphaltene precipitation on fluid flow and oil production from the vuggy, fractured reservoirs of the Taratunich Field.
Asphaltene precipitation has presented serious problems in the development of this field, which is located in the Bay of Campeche, Mexico. Asphaltene deposition has been reported both at the tubings and surface facilities. Special laboratory fluid and core studies and analysis of the well and reservoir performance data have been conducted in search of methods to mitigate or prevent this problem. Subsurface oil samples were collected for use in the laboratory analysis of the fluid to determine the composition, phase behavior and onset pressures of asphaltene and wax precipitation. Asphaltene was precipitated when the reservoir pressure declined below certain level. Laboratory flow tests were designed to measure also the rock flow capabilities as a function of pressure. Cores representing different rock types were used and different pressure levels were chosen spanning the range of asphaltene precipitation, which was determined from the fluid characterization study.
The analysis of the well and reservoir performance data revealed that lithology types and pore throat size play an important role in where asphaltene precipitates in the reservoirs. The results of the experiments showed that oil permeability decreases as the core pressure declines below the onset pressure of asphaltene precipitation. A dual porosity, single permeability (DPSP) numerical flow model was constructed with these experimental results, which were converted into tables of pore volume and transmissibility modifications. The reservoir simulator, Eclipse100, allowed the effects of asphaltene precipitation to be modeled through changes in pore volume and transmissibility with reservoir pressure. Since fracture system is the only conduit for fluid flow in DPSP flow models, the changes were applied to fracture system. The various experiments and their results, interpretation of the well and field performance data, as well as the construction of the simulation model are presented in this paper.
The Taratunich field was discovered in October 1989 with the drilling of TRT-201 in the JsK formation. The field produces oil from the Breccia (BPT-Ks) and Jurassic (JsK) formations. The field is a faulted anticline, which is divided into three main blocks, 101, 201 and 301 by major reverse faults (Figure 1). Two normal faults separate blocks 201 and 301. About 27 wells, including exploratory wells, have been drilled, and 22 have produced oil. Some wells in the JsK, particularly in block 101 and 201, have been plagued with asphaltene problems, resulting in production decline.