Production Logging Data Research Articles

プロダクション検層データに基づいたフラクチャリング坑井への追加穿孔の試み

In the Minami Nagaoka gas field located in Niigata Prefecture, Japan, additional perforations were conducted in a hydraulically fractured well to increase the productivity of the well. To our best knowledge, successful additiona lperforation treatments in hydraulically fractured wells have not been reported. A well, Minami Nagaoka MHF-1, was performed six-stages fracturing with limited perforation intervals. Since the production logging data was necessary to perform an efficient perforation job, the production logging was run just before the additional perforations. The additional perforations were conducted at some intervals where gas inflow concentrated to mitigate non-Darcy effects due to the excess gas inflow. Post-job evaluation confirmed that the additional perforations contributed to increase the productivity by a factor of two.

Characteristics of high-permeability zones using core analysis, and production logging data

Carbonate reservoirs are heterogeneous in nature and sometimes they contain natural fractures. Zones with extremely high permeability are commonly found in these reservoirs. These zones are a subject of concern for reservoir engineers, as they lead to early water breakthrough in oil producers and uneven sweep around water injectors. These zones cause many problems to production engineers during acid or other chemical placement. We conducted a study to identify and characterize high permeability zones using conventional petrophysical tests in conjunction with production logs (flow meter measurements). High permeability zones were identified and characterized using core data and production logging. These zones were found at the top of the formations examined, with a thickness up to 10 ft and they contributed more than 50% of the total well production. These zones had permeability greater than 20 Darcies and are sandwiched with two layers of low permeability (a few micro-darcies). The two low-permeability layers act as a barrier that minimizes cross-flow. Calliper log of the open hole indicated that hole enlargement and wash-out occurred at depths where these zones are located. Based on production data, it is evident that the flow profile was dominated by high flow from these zones. The mineralogy of super-k zones was mainly dolomite. The use of Amaefule et al.'s approach allows for a more precise definition of reservoir zonation. Excellent agreement was obtained between the cumulative distribution of reservoir quality index (RQI) and flow zone indicator (FZI) with well flow profile data for wells without natural fractures, whereas, no agreement was obtained for wells with significant natural fractures.

Jotun 4D: Characterization of fluid contact movement from time-lapse seismic and production logging tool data

Time-lapse (or 4D) seismic is a reservoir monitoring technology that has matured to the point where it can be considered a reliable reservoir surveillance tool. By analyzing differences of multiple seismic surveys acquired over a producing reservoir and by integration with conventional reservoir monitoring tools, 4D seismic data can provide valuable insight on dynamic reservoir properties such as fluid saturation, pressure and temperature. Many published case studies demonstrate that 4D seismic technology can optimize reservoir management and improve production efficiency. In this paper we describe the application of time-lapse seismic methods to the Norwegian North Sea Jotun Field to determine the extent of the oil-water contact (OWC) movement during the first three years of production.

Characterization of a Carbonate Reservoir With Pressure-Transient Tests and Production Logs: Tengiz Field, Kazakhstan

Summary The combination of pressure-transient and production-log (PL) analyses has proved valuable in characterizing reservoir flow behavior in the giant Tengiz field. Among the important findings is the absence of clear dual-porosity flow. This observation contradicts an earlier interpretation that the reservoir contains a well-connected, natural fracture network. Fracturing and other secondary porosity mechanisms play a role in enhancing matrix permeability, but their impact is insufficient to cause dual-porosity flow behavior to develop. Flow profiles measured with production logs consistently show several thin (10 to 30 ft) zones dominating well deliverability over the thick (up to 1,040 ft) perforation intervals at Tengiz. A comparison of PL results and core descriptions reveals a good correlation between high deliverability zones and probable exposure surfaces in the carbonate reservoir. Contrary to earlier postulations, results obtained from pressure-transient and PL data at Tengiz do not support rate-sensitive productivity indices (PI's). Inclusion of rate variations in reconciling buildup and drawdown test results addressed this issue. We developed wellbore hydraulic models and calibrated them with PL data for extending PI results to wells that do not have measured values. A simplified equation-of-state (EOS) fluid description was an important component of the models because the available black-oil fluid correlations do not provide reliable results for the 47°API volatile Tengiz oil. Clear trends in reservoir quality emerge from the PI results.

Soft computing: tools for intelligent reservoir characterization (IRESC) and optimum well placement (OWP)

An integrated methodology has been developed to identify nonlinear relationships and mapping between 3-D seismic data and production log data. This methodology has been applied to a producing field. The method uses conventional techniques such as geostatistical and classical pattern recognition in conjunction with modern techniques such as soft computing (neuro-computing, fuzzy logic, genetic computing, and probabilistic reasoning). An important goal of our research is to use clustering techniques to recognize the optimal location of a new well based on 3-D seismic data and available production-log data. The classification task was accomplished in three ways; (1) k-mean clustering, (2) fuzzy c-means clustering, and (3) neural network clustering to recognize similarity cubes. Relationships between each cluster and production-log data can be recognized around the well bore and the results used to reconstruct and extrapolate production-log data away from the well bore. This advanced technique for analysis and interpretation of 3-D seismic and log data can be used to predict: (1) mapping between production data and seismic data, (2) reservoir connectivity based on multi-attribute analysis, (3) pay zone estimation, and (4) optimum well placement.

Characterizing the Greater Burgan Field With Geochemical and Other Field Data

Summary This paper describes recent results from an ongoing geochemical study of the supergiant Greater Burgan field, Kuwait. Oil occurs in a number of vertically separated reservoirs including the Jurassic Marrat reservoir and Cretaceous-Minagish, -Third Burgan, -Fourth Burgan, -Mauddud, and -Wara reservoirs. The Third and Fourth Burgan sands are the most important producing reservoirs. Over 100 oils representing all major producing reservoirs have been analyzed using oil fingerprinting as the principal method, but also supported by gravity, sulfur, and pressure-volume-temperature (PVT) measurements. From a reservoir management perspective, an important feature of the field is the approximately 1,200-ft-long hydrocarbon column which extends across the Burgan and Wara reservoirs. Oil composition varies with depth in this thick oil column. For example, oil gravity varies in a nonlinear fashion from about 10°API near the oil/water contact to about 39°API at the shallowest Wara reservoir. This gravity-depth relationship makes identification of reservoir compartments solely from fluid property data difficult. Including oil geochemistry in the traditional mix of PVT and production logging data improves the understanding of compartmentalization and fluid flow in the reservoir, both in a vertical and lateral sense. The composition of reservoir fluids is controlled by a number of geological and physical processes. We attempted to identify unique sets of geochemical parameters that were sensitive to specific oil alteration processes. One set of geochemical properties correlated strongly with gravity and is, therefore, related to the gravity-segregation process. A second set of parameters showed essentially no correlation with gravity or depth but established unique oil fingerprints for most of the major producing reservoirs and identified a number of different oil groups within the Burgan and Wara reservoirs. We interpret the presence of these oil groups to indicate reservoir compartments owing to laterally continuous shales and faults which act as seals on a geologic time frame. More tentative is the identification of production time frame barriers from the fluid composition data. The oil fingerprint data have been used to distinguish oils from the major producing reservoirs and evaluate hydrocarbon continuity within the reservoirs.

Novel Wax-Diverter Technology Allows Successful Scale-Inhibitor Squeeze Treatment in a Subsea Horizontal Well

Summary In this article we present field results from two scale squeeze treatments carried out on the same subsea horizontal well from the Strathspey field in the North Sea. The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulfate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This latter utilized a thermally degraded pelleted wax diverter to temporarily impair the injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the midsection of the horizontal well. In this article we show the significance of production logging tool data to evaluate the location of deposited scale and water production prior to a squeeze treatment. These data were used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelleted thermally degraded wax diverter to prevent further loss of scale inhibitor to the heel region. The action of the wax diverter allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of the diverter selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (nonradioactive tracers, inhibitor and ion concentrations) data were recorded. These data will be used to indicate the success of the diversion treatment by a comparison with the first squeeze applied to the same well 10 months previously. This is the first successful application of a thermally degraded wax diverter to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process upset during flowback and no decline in well production while allowing the well bore to be protected from continued sulfate scale formation. In this article it is clearly shown that with the correct selection of both the scale inhibitor and diverter agent together with ulitization of all available information relating to the reservoir, it is possible to squeeze scale inhibitors into subsea horizontal wells without the need for intervention by expensive coiled tubing from a diving support vessel.

Reservoir and Production Analysis of the K40 Sand, South Timbalier 295, Offshore Louisiana, with Comparison to Time-Lapse (4-D) Seismic Results

Reservoir and production characteristics of the K40 sand (South Timbalier Block 295, offshore Louisiana) are used to track the oil-water contact as it moved vertically 80 m between 1988 and 1994. This zone of water sweep is associated with a strong decrease in seismic amplitudes observed from comparison of 3-D (three-dimensional) seismic curves acquired before hydrocarbon production (1988) and during production (1994). The Pliocene K40 sand is an overpressured (0.80 psi/ft) turbidite reservoir deposited in a slope minibasin. Wireline and seismic data are used to develop a geologic model for this reservoir. This analysis, combined with production history and log data, indicates that relatively uniform water sweep was effectively imaged by time-lapse (4-D) seismic over most of the reservoir. The lack of seismic dimming in some parts of the reservoir is attributed to poor drainage of low-permeability lithofacies. In addition, it may not be possible to image drainage of reservoir zones with less than 10 m of original net pay with these data. These results illustrate the potential of time-lapse seismic analysis for illuminating the dynamic behavior of producing reservoirs and indicate that preproduction seismic surveys, not originally intended for use in time-lapse (4-D) seismic analysis, have value as baselines for seismic monitoring studies.

Reservoir Performance of Late Eocene Incised Valley Fills, Cusiana Field, Llanos Foothills, Eastern Colombia.: ABSTRACT

The Cusiana Field is located in the Llanos Foothills of Eastern Colombia. The principal reservoir is the late Eocene Mirador Formation which comprises >50% of reserves. Currently the Mirador reservoir is providing nearly all of the 150,00bopd of production from the Cusiana Field. The Mirador reservoir comprises a stack of incised valley deposits. The fills of the valleys are dominated by quartz arenite sandstones. The average porosity of the valley sandstones is 8% which reflects abundant quartz cement ({approximately}14%) and significant compaction during deep burial ({approximately}20,000feet). Single valleys are up to 70 feet thick and exhibit a distinctive bipartite fill that reflects changing energy conditions during filling. Bases of valleys have the coarsest grain size and have sedimentological and trace fossil evidence for deposition in highly stressed, brackish water environments. The upper parts of the valleys are typically finer grained and were deposited in more saline settings. Despite the low porosity of the Mirador valleys, drill stem tests and production log data show that they have phenomenal performance characteristics. Rates of {ge}10,000bopd are achieved from single valleys. Bases of the valley fills are the key contributors to flow. Integration of detailed core and pore system analysis with the reservoir performancemore » data shows that the permeability fabric of the Mirador can be explained by original depositional architecture and simple loss of primary porosity. Comparison of Cusiana with other quartz-rich sandstones from around the world suggests that it`s low porosity/high performance is predictable.« less

Case Study of a Horizontal Well in a Layered Rotliegendes Gas Field

Summary A horizontal well was drilled in the Ravenspum North field to drain a thin gas column above the aquifer. The field has a significant variation in reservoir quality, with most of the wells requiring stimulation by hydraulic fracturing. The reservoir is formed from a stacked sequence of aeolian dune and fluvial sandstones with a wide permeability range. The horizontal well was chosen as an alternative to stimulation by hydraulic fracturing to avoid water production from the aquifer. The well was successful, flowing at higher gas rates than expected with no water production. Production, core, and production logging data were used to demonstrate greater than expected lateral heterogeneity in the field. The horizontal well was found to be appropriate for the very specific conditions found in one part of the reservoir; however, the overall development strategy of using hydraulic fracture remains the preferred technique.

水平坑井内の流体挙動解析 由利原ＳＫ‐１５号井のデータを用いて

A case study was performed on the interaction between the flow behavior in a horizontal wellbore and the fluid influx from a heterogeneous reservoir. This has been recognized as one of the most important, yet unsolved problems in pertoleum engineering.Field data such as fluid influx distribution from the reservoir as well as pressure and fluid density distributions were acquired along a horizontal wellbore named “Yurihara SK-15” at the Yurihara Oil and Gas Field in Akita Prefecture, Japan.A mechanistic model POPHOZN was used as a tool to discuss key parameters affecting the steady-state production behavior of the horizontal well.The analysis of the production logging data demonstrated that POPHOZN could be applied for field application.The followings have been conducted as part of the present study on the analysis of flow behavior due to confluent fluid flux along a horizontal wellbore:(1) Field data such as fluid influx from the reservoir, pressure and fluid density distributions along a horizontal wellbore was successfully acquired by running a spinner flow meter and a densitometer with coiled tubings at the Yurihara Oil and Gas Field.(2) It was found that the gas-oil two-phase flow occurred in the horizontal section due to saturated reservoir conditions. The characteristics of the two-phase flow could be reasonably accounted for calculating pressure drop and fluid density distribution in the horizontal wellbore by the model POPHOZN.(3) The analysis of the production logging data demonstrated that the overall performance of the proposed model POPHOZN successfully simulated the interaction between the heterogeneous reservoir and the horizontal well configuration, and the flow hydrodynamics along horizontal wellbore could be physically expressed.