In this paper, a technique for upscaling of absolute permeability in the well vicinity on CPG (Corner-Point Geometry) gridblocks is presented. The near-well upscaling procedure is very useful for well performance prediction. It can assure the coherence of well results by using fine grid on coarse grid simulations.
The near-well upscaling procedure is developed for advanced wells in 3D. Transmissibilities are upscaled from Cartesian fine grid issued from a geostatistical to CPG coarse grid used for flow simulations. To overcome the difficulty of complex geometrical intersections between fine gridblocks and coarse gridblocks, three approaches (geometrical approach, numerical approach and topological approach) are proposed and compared for flux upscaling. The topological approach, which needs a topological structure for gridblock regrouping in the vertical direction, seems the most promising. The near-well formation damage, which can be predicted using another numerical model, can also be integrated into the near-well upscaling procedure.
Asphaltene precipitation is a nearby wellbore phenomenon with strong adverse effects in rock permeability affecting the production operations. However, a complete characterization of the asphaltene precipitation effect, namely quantifying the degree, scale and mechanisms of permeability reduction still remains to be resolved. In this paper we report the results of a series experiments on characterizing the asphaltene precipitation effect on permeability reduction. The experiments are also unique in providing the precipitation effects on the end point relative permeability at Siw.
For quantifying the degree and scale of asphaltene precipitation a set of experiments are designed to induce permeability reduction along the flow direction. Then the plugged and unplugged pore ratios were quantified using SEM images taken at five different points from the core inlet. In all experiments, total plugging has occurred between 40 to 60-pore volume injection. It has also been found that within a distance of 0.3 total core length, approximately 80 % of the plugging has occurred indicating the ‘snowballing' nature of mechanical entrapment.
Then the two major mechanisms of asphaltene deposition namely dynamic asphaltene adsorption and mechanical entrapment were quantified by reversing the flow direction. The reversal of the flow have initially resulted in approximately 80 percent permeability recovery, indicating that 80 percent of the permeability reduction is caused by mechanical entrapment. Then a period of simultaneously acting recovery and impairment mechanisms has been observed finally followed by impairment mechanism only. After the initial recovery period, a consequent flooding of one the cores with toluene were able to establish the original permeability. This additional recovery is attributed to removal of the adsorbed asphaltenes.
Downhole demulsification of crude oil increases well production and profitability by reducing vertical flow pressure loss. This paper presents a practical, field-tested method to accomplish downhole demulsification without the mechanical complexities of the conventional downhole injection system. Chemical is injected at surface with a pneumatic dosing pump into the gas lift stream. Lift gas entering into the tubing-casing annulus carries the chemical downhole to the injection point deep into the tubing and blends it with the well fluid to prevent emulsification. Production improves after a few days of chemical injection as the downhole demulsification process stabilizes. Successive trials have proved the effectiveness of the approach in terms of improved production. In view of the simplicity and cost effectiveness of the method, it has also been applied in naturally flowing wells that produce below their potential because of emulsion. Case study and result of such trial have been discussed in the paper that shows promising success. It has broadened the application scope of the system to emulsion-infested natural flow wells.
Bahrain Oil Field
Bahrain field is an asymmetrical anticline trending in the North-South direction. The sedimentary column extends from Cambrian Saq sandstone to the Miocene reefal deposits exposed on the surface. The field was discovered in 1932 (Fig. 1) and it contains twenty-two reservoirs (Fig. 2) with the hydrocarbon content varying from tarry oil in Aruma to dry gas in Khuff reservoirs. Mauddud zone within Wasia group of formations is the major oil reservoir of the field. Gas injection into Mauddud zone continuing since 1938 has developed a large gas cap1. Besides Mauddud, other producing oil bearing formations are Nahr Umr (Ca, Cb shaly limestones and Cc, Cd sandstones), Wara (Ac sandstone), Ahmadi (Aa, Ab limestones), Rumaila (Ostracod and Magwa limestones) and Mishrif (Rubble limestone) with depth range of 2500 ft to 1250 ft. There are 700 wells in Bahrain field wherein 260 are naturally flowing, 160 on continuous gas lift, about 70 each on beam pump and intermittent gas lift, and remaining 140 are other types including injectors, gas producers, abandoned and suspended wells. Average gas lift well production varies between 40-4000 bpd of liquid with W.C. ranging from 5 to 98%. Wells flow through separate 3/4 inch line ranging in length from 100-12000 ft to the common headers at 16 well manifolds spread across the field. Lift gas is fed into individual wells at about 1050 psig through 2-inch lines from supply headers running along north-south direction.
Typical Continuous gas lift and natural flow wells (Fig. 3) have sliding sleeves and intermittent gas lift wells have mandrels in the completion string at about 2200 ft depth. Oil gravity and viscosities of various zones range from 12-37 (°API and 4-564 Cst respectively (Table-1). Wells completed in Ac, Mauddud, Ca, Cb, Cc and Cd zones, which are well within the gas cap area, are generally naturally flowing while the flank wells are on gas lift with tendency to become self-flowing. Gas lift wells completed in Cd and Ac zones, particularly in the south of the field, have severe emulsion problem when the producing W.C. is within 60% to 95% range. Recently, emulsion production have been observed in some gas lift as well as natural flowing wells which are located inside the gas cap area and completed in Mauddud, Ca, Cb and Cc zones. Other low-pressure shallow zone wells are normally produced on pump or intermittent gas lift and a few of them flow emulsified crude.
Oil prices rarely reflected those of a free market. The history of the oil industry documents several instances of monopoly and price fixing. In the last decade however, globalization and the ensuing economic policies raised the possibility that the oil market may finally be free from production and price controls. This paper will analyze the oil supply and demand patterns under scenarios of free market and will predict short and long-term price patterns under these conditions.
The Salt Creek Field, located approximately 110 miles northeast of Midland, TX, is a heterogeneous, Pennsylvanian-aged carbonate build-up in the Permian Basin. Successive implementation of infill drilling and improved recovery processes, coupled with effective reservoir management, have led to oil recovery of over 50 percent and expected ultimate recovery as high as 60 percent.
Salt Creek field was discovered in 1950 and a centerline water injection program began in 1953. A 40-acre development program was initiated in 1970 and was completed in 1984. The waterflood pattern was also changed from a centerline drive to a field wide inverted nine-spot. In 1985, a reservoir continuity study led to a 20-acre infill drilling program that added over 150 wells, changing the pattern to a five-spot. A miscible carbon dioxide (CO2) flood was initiated in 1993, and then expanded to the underlying residual oil zone.
Reservoir management has been a key element in maximizing recovery at Salt Creek. Consistent acquisition and maintenance of appropriate well and reservoir data has allowed detailed zonal tracking of production and injection volumes (CO2 and water). Geologic models, in combination with production logs and production data, have been used to manage and optimize CO2 and water injection at the flow unit level. Effective communication processes have been established between the field operators and the technical staff to calibrate engineering and geologic data with field experience and to enhance real-time decision making. A 3D seismic survey covering the entire field was acquired in 2000 to better define productive field limits and reservoir geometry. Currently, a study integrating engineering and geoscience data is underway to further improve reservoir characterization. The study is expected to result in improved sweep efficiency through better conformance control and additional drillwells to capture unswept reserves.
The objective of this paper is to share the knowledge mapping techniques and experiences of those involved in this activity.
The purpose of a knowledge map is to show people in the organization where to go when they need expertise or have expertise to share. A knowledge map is a picture of what exists in the company as well as where it is located. It therefore can be used as a tool to discover opportunities to be exploited and gaps to be filled. When the same reservoir has different production policies for different portions of the field, Planners from all teams suffer from incomplete data. Information is shared when available, as in the case of the full-field reservoir model. But this is not thought to be optimal, when other reservoir studies have been conducted in isolation and expertise is not shared. A more coordinated approach is required that would continuously bring together all the available knowledge and make it always freely available to analysts and decision makers.
This paper demonstrates the importance of valid on-site measurements of hydrogen sulphide (H2S) and carbon dioxide (CO2) in gas wells in relation to corrosion management, notably for the proper selection of tubular goods, where material choice can result in cost changes of millions of dollars.
The problems of loss of H2S during sample storage are well known, providing a strong justification for on-site measurements. This work has looked at the ways to measure and validate both H 2S and CO2 on-site. Conflicting values recorded on-site confirm the difficulty of getting reliable H 2S and CO2 measurements.
H2S measurements at three gas-condensate wells were made on bottom hole samples involving a special non-reactive wireline sampler service. The intention was to obtain more accurate reservoir concentrations by avoiding anticipated losses through reaction or absorption on the production tubing. However, comparative surface measurements on the separator gas stream gave higher concentrations in nearly all cases, and a thorough investigation of the data confirmed that the separator gas measurements, made using simple equipment, were significantly more reliable. In addition to the measurements themselves, it is demonstrated that well history, well conditioning and producing interval must be taken into account when interpreting measurements. For example, one test measured H2S production only after an acid fracturing treatment, implying that the original formation fluid contained extremely low or possibly no H2S.
The paper makes recommendations for on-site measurements and their validation including the use of two independent methods for H2S determination.
In crude oil production, the generation of heavy oil/water emulsions can result in a significant drop in the production rate due to the high viscosities of the emulsions. The strong agitation and mixing that takes place at the inlet of the well bore together with the presence of the naturally existing emulsifying agents in the crude contribute to the formation of the emulsion. A number of methods can be used to mitigate this problem such as the injection of surfactants into the formation and surface treatment. The objective of this paper is two-folds. Firstly, the results of an experimental program carried out to evaluate the efficiency of several surfactants to demulsify crude oil / water emulsions are presented. Secondly, a novel cost effective technique for injecting the surfactant into the well utilising existing gas lift facilities at the well heads is described together with a number of other techniques which have been tested for treatment of emulsions.
The experimental study was performed on crude oil/water emulsion samples obtained from two sandstone reservoirs in the Bahrain field. The measurements included effects of surfactants on the degree of demulsification, surface tension and shear viscosity. An optimum surfactant/emulsion volume ratio of around 1.5 to 2% was noticed in most cases for the specific wells investigated. The addition of surfactants considerably reduced the shear viscosity and surface tension of the emulsion. As expected the surface interfacial tensions decreased with increasing temperature.
Over time pipelines in the field, transporting high-pressure gas, have exhibited severe external wear at support locations, especially near bends, due to expansion/contraction with respect to climatic conditions.
This paper describes on-stream inspection survey techniques and the subsequent repair/inspection methods carried out, to ensure that pipeline integrity is maintained. The first gas transmission lines were constructed around 30 years ago, meeting the code requirements of ASME/ANSI B31.8, with an operating pressure of approximately 1050 psi. In July 1998, at one location, a 12" gas transmission line leaked due to external wear of the pipe at its point contact with a transverse support.
This paper also focuses on the significance of design location class, field investigation, corrective & preventive measures, repair & acceptance methods.
In recent decades Bahrain has experienced a rapid growth in gas demand for industrial use, electricity generation, gas injection, and artificial lift. The main source of gas for these needs is the Khuff reservoir. The Khuff gas is currently being produced from 29 prolific gas wells.
To enhance the productivity of the Khuff reservoir a matrix acid stimulation program was undertaken using coiled tubing and a temporary non damaging gel plug system with complete regained permeability to isolate the high-permeability producing zone while the low-permeability gas-producing zone was being stimulated. Because the isolated zone is also producing, the gel system has to be completely non damaging with full regained permeability to this isolated formation.
The success of stimulating a low-permeability interval where a high-permeability producing zone is also present is primarily dependent on the ability to divert the respective stimulation fluid into the zone of lower permeability and productivity. Several methods are commonly used to divert the stimulating fluid in the non productive zone. These methods are dependent on the type of stimulation and configuration of the completion.
If coiled tubing is used for through-tubing stimulation in cased holes, inflatable packers are normally considered for isolation. However, inflatable packers have limited expansion ratios and pressure capabilities. The previous use of ball sealers gave very limited results of only 10% incremental gas production.
This paper will present the successful stimulation techniques and results of a unique and cost effective solution for a well where two intervals with different permeabilities were isolated without the high risks and costs of using a mechanical packer. Coiled tubing was used to stimulate the lower interval while the upper producing interval was isolated using a temporary chemical packer. Temperature in this well exceeded 270°F.