High-temperature fracturing-fluid breaker systems have been used in fracturing operations for the past several years. The advantage of using these systems has been improved fracture conductivity, but there has been an increased risk of poor proppant placement and premature screenouts resulting from early viscosity reductions as the fluid is exposed to high temperatures. In many cases, this problem could only be avoided by adding breaker to the final portion of the proppant stages, essentially improving the fracture conductivity in the nearwellbore region without enhancing the conductivity of most of the proppant pack.
This paper highlights innovative research for developing high-temperature breakers that work synergistically with gel stabilizers to maintain excellent gel viscosity. This viscosity allows sufficient time to place the treatment while still providing a more complete break and improved fracture conductivity. Laboratory testing has shown that this high-temperature breaker system can be used effectively at temperatures as high as 350 F without sacrificing early-time fluid viscosity or proppant placement, while still providing dramatic improvements in fracture conductivity.
Field production has been analyzed and shows the combined benefits of improved proppant placement and increased fracture conductivities obtained with the application of this technology.
Demand for natural gas in Mexico is expanding. This increase in the use of gas is due to a rapidly developing household market and to substitution with gas of heavy fuel oils for industrial uses. Increasingly stringent environmental standards are incentivating this demand. Pemex Exploration and Production, as the government agency responsible for finding, developing and producing Mexico's oil and gas resources has implemented strategic projects to fulfill the growing need for gas supplies. This presentation gives an overview of the actions that Pemex E & P has and is taking in the Burgos and Veracruz basins to help satisfy the nation's need for gas.
Both Burgos and Veracruz are tertiary siliciclastic basins located in the western margin of the Gulf of Mexico proper, and both are producers of dry sweet gas. Burgos is located in northeastern Mexico, it covers 49,800 km2. It is limited to the west and south by east diping mesozoic marls and limestones, to the east by the continental slope and to the north by the Rio Bravo del Norte (Rio Grande River), although the basin itself continues into South Texas, where it is known as the Rio Grande Embayment (Texas Railroad Commission, District IV). The Veracruz basin with an areal extent of 18,000 Km2 is located on east central Mexico and is limited to the west by a laramide thrusted foldbelt (producer of sour wet gas, condensates and some oils), to the north by recent volcanic rocks, to the east by the continental slope and to the south it becomes the Isthmus Saline basin. Dry gas production reached a maximum of 620 MMcfd in 1970 for Burgos and 45 MMcfd in 1971 for Veracruz.
PETROLEOS MEXICANOS and specifically PEMEX EXPLORACION y PRODUCCION has restructured the former regions around the oil fields called "assets", and this sector has focused on units of businesses, and the area of Drilling and Well Maintenance became a state-owned company which gives those services by changing its traditional technical focus to one emphasizing the technical-financial evaluation of its operations.
The present work describes the efforts to have a "Drilling Cost and Well Maintenance System", which allows transparence in the financial evaluation of the operations of the new state-owned company. The former institutional systems of PEMEX EXPLORACION y PRODUCCION used to total the information. The above way made the availability of its own financial statements difficult for the new organization to realize.
The definition of the financial structure of a new organization needs the setting of the methodology, inscriptions and the necessary concepts so that information can be reliable, useful and timely. One of these elements is the risk analysis, which has become an integral part of the decision maker in the oil industry as to know the economical feasibility of the projects. Therefore, the model of risk analysis used is shown in this work, including the "Monte Carlo" simulation with data of regional costs of the Operative Northeast Unit, statistical methods, analytic models, optimization, decision trees, sensitivity analysis and influence diagrams so that costs and required times for drilling a well can be forecast.
In a word, it has been possible to establish the "Drilling Cost and Well Maintenance System of PPMP" as a primary support of the financial structure of the new state-owned company. This will help PPMP to obtain its own financial statements and, of course, its physical-financial evaluation.
A case of identifying and analysis of key variables into a crude-oil reception, conditioning and distribution station using Statistical Process Control Techniques (SPC), is presented. The station identified as "Terminal Maritima de Dos Bocas" (TMDB), situated near the town of Paraiso in the SouthEast Mexican state of Tabasco, receives eight crude lines from Campeche offshore plataforms and some South land-reservoirs, moreover it conditioning and distributes crude-oil for international and domestic commerce.
Owing the high international markets crude-oil competition and its respective demand of more strict conditions of quality for it commerce, it is neccesary to incorporate new technologies to the terminal looking for satisfying present and future needs. To do this, it was primary important to make a review of the process and proceedings in the terminal driven, with the objetive of identify those variables with high influence on its products quality and which determines it (i.e. Key Variables). We follow the methodology of Statistical Process Control to find out this key-variables and to quantify the benefits we should have for the implementation of such tehcniques as first step to the general application of the methodology in real time.
The information available for characterizing a reservoir is insufficient to develop a unique model. However, by applying the proper reservoir characterization methodology, a model can be constructed that optimizes and integrates all the data and thus facilitates the identification of reserve growth potential. This methodology contains four steps: (1) determining reservoir architecture, (2) establishing fluid-flow trends, (3) constructing reservoir model, and (4) identifying reserve growth potential. The key to determining reservoir architecture is the application of genetic sequence stratigraphy. The reservoir architecture is determined by ascertaining the internal reservoir stratigraphy, defining the stratigraphic unit geometries, interpreting the distribution of depositional environments, and combining stratigraphy with structural character. Establishing fluid-flow trends should be accomplished within the context of the stratigraphy. This step includes determining the initial fluid and rock-fluid properties, generating a production-time-series analysis, analyzing any variation in fluid chemistry, assessing well test data, and determining the direction of injected fluids. The third and pivotal step of constructing a reservoir model by integrating reservoir architecture and fluid-flow trends has four steps. It begins with designing geologically based petrophysical models, then concurrently identifying the correspondence between reservoir architecture and fluid-flow trends, then establishing the reservoir model flow unit and compartment components. Next, the petrophysical properties are distributed spatially and the hydrocarbons in place are calculated. The final step is identifying reserve growth potential. It is accomplished by calculating reserves, delineating the remaining hydrocarbon resource, generating reserve growth concepts, and targeting reserve growth opportunities.
A reliable and high performance novel method of Flame and Gas Optical Spectral Analysis (line of sight) was developed to meet the specific flame and gas detection needs of the petrochemical industry.
Petrochemical industries, especially the offshore and unmanned (unattended) areas in onshore refineries, pose a major safety hazard with respect to potential explosions and fire events. Unwanted fuel spills or fugitive flammable vapour clouds, migrating along congested pipe lines and hot production areas may cause upon ignition significant loss or damage. To help prevent events like the catastrophic fire that destroyed the offshore oil platform Piper Alpha in July 1988, a reliable and fast gas and flame detection system can be used to trigger effective risk management actions.
The present paper describes a patented method of Triple Optical Spectral Analysis employed for the detection of various gases in the air according to their unique "spectral finger print" absorption characteristics of radiation, as well as for analysis of emission and absorption radiation from combustion processes (hot CO2) for flame detection purpose.
The method has been applied in the development of unique gas and flame monitoring systems designed for "high risk - harsh/extreme weather conditions continuous operation" - These systems have been recently installed on several offshore platforms and oil rigs as well as on "Floating Production Storage and Offloading" - FPSO vessels.
The systems advantages and limitations as well as several installations and test data are presented. Various atmospheric conditions (direct and reflected sunlight, fog, rain, hail, snow) as well as false alarm stimulus (from radiation sources, flare stack, black body radiation, smoke, CO2 and atmospheric gases) are discussed.
Powell, R.J. (Halliburton Energy Services Inc.) | McCabe, M.A. (Halliburton Energy Services Inc.) | Slabaugh, B.F. (Halliburton Energy Services Inc.) | Terracina, J.M. (Halliburton Energy Services Inc.) | McPike, T. (Shell E & P Technology Co.)
This paper was prepared for presentation at the 1998 International Petroleum Conference and Exhibition of Mexico held in Villahermosa, Mexico, 3-5 March.
Focusing on the Smoerbukk (Smorbukk) fields it is proposed to introduce imbibition capillary pressure by a new method which entails representing Pc analytically starting from the primary drainage curve. Predicted saturation is shown to agree with wireline log data from a Smoerbukk South well were the initial distribution of saturation was likely established by an imbibition process. Numerical simulation shows that introducing imbibition capillary pressure siguificantly reduced predicted water cut in downflanks producers as compared to simulations presuming no capillary transition zone. This allowed repositioning the producers closer to the oil-water contact, thereby increasing recovery.
Finally, it is demonstrated that numerical simulation efficiency improved by introducing imbibition capillary pressure.
Simulation of multiphase flow in porous media requires knowledge of relative permeability functions. A commonly used unsteady-state method of estimating relative permeability is based on interpreting flow data collected from laboratory displacement experiments. In this paper, refinements are outlined, for improving the accuracy of estimated relative permeability pararmeters by accounting for thermal effects for produced fluids, utilizing pre breakthrough differential pressure data in cases where capillary forces are neglected, elimination of convergence problems in history-matching algorithms, and improving the reliability of injected phase relative permeability estimates.
For the gravimetric method of collecting displacement data, the existing procedure of calculating production volumes is improved to account for thermal expansion of fluids in collection vessels, both for imbibition and drainage displacement. The parameter estimation technique is used to determine relative permeability. A semi-analytical procedure, based on the JBN method, utilizes pre-breakthrough differential pressure data, in cases when capillary forces are neglected. This is especially important for low permeability samples, where post-breakthrough production data could be limited. Otherwise, capillary and gravitational forces are accounted for using a finite- difference method.
The history matching procedure requires minimizing the objective function, which is a measure of the deviation between simulated and experimental data. The simulated annealing method is used to avoid possible convergence of the minimization routine to a local, rather than the global minimum of the objective function. Interpretation of relative permeability of the injected fluid from displacement experiments is shown to be less precise than for the displaced fluid. The theoretical analysis rationalizes acquisition of more data during early phases of a displacement experiment. Optimization features discussed in this paper are incorporated in a new, relative permeability simulator.
This paper focuses on Shell's practice for deepwater US Gulf of Mexico integrated geoscience studies with explanations and examples on how to apply and use the methodology. The applicability of high-resolution geophysical data in deepwater depends on: 1) the usefulness and applicability of 3-D exploration-level seismic data for geohazard studies through the use of renderings and other 3 -D workstation related products, 2) a review of side scan sonar and subbottom profiler methods and their appropriateness. Discussed also is the usefulness of multifold data and why 3-D high-resolution acquisition may be a necessary requirement for the future. In addition, present deepwater geotechnical investigation practices are discussed.
Examples of integrated geoscience studies are used to illustrate their use in the design of deepwater foundations.