The paper describes the reservoir management experiences of Kerisi field after seven years of production. Kerisi field is located in Block B of South Natuna Sea and comprises five separate reservoirs in three geological zones.
Forty seven percent of the reservoir hydrocarbons are located in the Upper Gabus Massive West (UGMW) reservoir; optimum production from this formation is expected to be reached by injecting gas at the gas cap. The source of injected gas is from all five Kerisi reservoirs and the nearby Hiu field. The liquid hydrocarbon production from UGMW and the production/injection of Kerisi – Hiu produced gas in this formation is of high importance to the future development stage of Kerisi – Hiu field.
The initial reservoir management strategy was to optimize oil value with injection while meeting gas sales requirements. Both gas sales commitments and injection targets were honored with high Kerisi – Hiu production and the strong performance from other gas fields.
With time, other gas fields became depleted faster than expected. Thus, it was decided to reduce gas injection rate in UGMW and produce more Kerisi and Hiu gas to increase gas sales volumes. The reduced of injection rates improved short term economic of the fields, but the effect to reservoir and long term economic benefit still needs evaluation.
This paper will (1) show the impact of varying injection rate at UGMW to the overall Kerisi – Hiu field future production, include oil, gas, condensate, and LPG, (2) discuss an updated – improved reservoir management strategy, and (3) present an economic evaluation of the updated reservoir management strategy for the Kerisi – Hiu fields.
The purpose of the paper is to share lessons learned in the evaluation of historical performance, data acquisition and monitoring, static and dynamic modeling, history matching, prediction of future performance, and the dynamics of reservoir management strategy which support future profitable opportunities.
A statistical analysis is performed upon geochemical data gathered in, a 1972 study or the Geological Survey or Canada. The present study, as did the earlier one, tests the effectiveness or present study, as did the earlier one, tests the effectiveness or petroleum geochemical prospecting by comparing anomalous surface petroleum geochemical prospecting by comparing anomalous surface geochemical values with the underlying oil and gas pools in the Olds-Caroline area or Alberta. Our different statistical method, applied to the same data, shows that distributions or anomalies are related to the oil and gas pools. This is contrary to the conclusions or the Canadian study which states that the anomalous points are random with respect to the oil and gas pools. The probability that the extreme sample values observed occur by sheer chance is so small that it must be concluded that they are not random. it is also our determination that data refining is unnecessary and confounding, particularly with regard to carbonate corrections. Each or the ten particularly with regard to carbonate corrections. Each or the ten conclusions or the earlier study are evaluated. Surface, geochemical prospecting based upon adsorbed gases is recommended as an exploration prospecting based upon adsorbed gases is recommended as an exploration tool.
Most mineral deposits found in sediments (petroleum, sulfur, uranium and many others) are associated with modifications of the geo-physico-chemical characteristics of the sediments caused by the genesis of the mineral deposits or by their proximity. The most distinctive characteristics of sediments which are so modified are the reduction-oxidation potential (or redox potential or Eh), the acid-base relations (or pH) and the salinity (as reflected by chloride content). Four distinct approaches may be followed in order to map the sedimentary environment a s modified by the presence of ore bodies at depth: 1. Surface mapping of Eh and pH and the derivation of a significant mapping parameter, the Vertical Mineral Proximity Index, the value of which depends on the mineral sought and on the chemical composition of the host rock. 2. Subsurface mapping of Eh, pH, chlorides and sulfides from samples of rocks obtained as drill cuttings from the mud returns and the derivation of a Lateral Mineral Proximity Index within an expected host rock. 3. Mud logging of Eh, pH and chlorides by inserting a suitable set of electrodes in the mud returns from a rotary drilling well using an appropriate drilling fluid and recording continuously the various parameters as the well is drilled. 4. Well logging of Eh, pH and chlorides by using wire-line sonde equipped with the appropriate set of electrodes and provided an appropriate drilling fluid stands in the well bore and logging after equilibrium with the formations has been approached. Under certain conditions the mud in the hole may have to be chemically treated or replaced with an adequate fluid in order to enhance the measured parameters. Example surveys of each type illustrate the various environmental exploration techniques.
Most mineral deposits found in sediments (petroleum, sulfur, uranium and many others) are associated with modifications of the geophysico-chemical characteristics of the sediments caused by the genesis of the mineral deposits or by their proximity. The most distinctive characteristics of sediments which are so modified are the reductionoxidation potential (or redox potential or Eh), the acid-base relations (or pH) and the salinity (as reflected by chloride content). Four distinct approaches may be followed in order to map the sedimentary environment as modified by the presence of ore bodies at depth: 1. 2. 3. Surface mapping of Eh and pH and the derivation of a significant mapping parame,ter,,the Vertical Mineral Proximity Index, the value of which depends on the mineral sought and on the chemical composition of the host rock. Subsurface mapping of Eh, pH, chlorides and sulfides from samples of rocks obtained as drill cuttings from the mud returns and the derivation of a ...
Pressure maintenance, gas injection operations was initiated in the Hilbig field, Bastrop County, Tex., in Oct. 1933, only eight months after the field was discovered. The Hilbig field produces from a porous serpentine plug, and the primary producing mechanism for this reservoir was dissolved gas drive. Ninety per cent of all produced gas has been returned to the reservoir and the project has been characterized by a high degree of gravity drainage and excellent performance. An estimated 75 per cent of the original oil in place will be recovered as a result of this program, as compared to a 51 per cent recovery under the primary drive mechanism.
The Hilbig field, which is located in southwestern Bastrop County, Tex., was discovered on Feb. 15, 1933, with the drilling of Humble's Annie Hasler 1 (now Hilbig Oil Unit 13). This well was completed from 2,006 to 2,115 ft subsea and produced at a rate of 1,700 STB/D on initial test. The Hilbig field produces from a porous supentine plug. The serpentine (Mg(OH)SiO-HO) is dull to dark green in color, fragmented, containing varying quantities of calcareous material as part of the matrix. From Feb. to April, 1933, eight more wells were drilled, four of which were dry holes and four were oil wells. By Sept., 1933, Humble had drilled eight additional oil wells and one dry hole. There are currently 13 completions in the reservoir-one injection well and 12 oil wells. All wells in the Hilbig field were competed in open hole with 7-in. casing set to within 7 ft of the top of the serpentine plug. The standard practice was to core below the production casing with a 6 1/8-in. core assembly until sufficient porosity had been penetrated to obtain satisfactory production.
Fig. 1 is s structure map of the Hilbig serpentine reservoir. The crest of the plug lies at about 1,875 ft subsea while the estimated water-oil contact is at 2,185 ft subsea. The productive area of this reservoir covers about 300 acres. The base of the serpentine lies at depths varying from 2,205 to 2,432 ft subsea. The serpentine was extruded by a volcanic process and it is believed that the porosity was created by the expansion of escaping gases. Porosity from core data ranges from 0 to 37 per cent and averages 24.1 per cent. Permeabilities range up to 570 md. Cores from wells located in the central portion of the reservoir were analyzed, but core analysis data are not available for wells drilled near the edge of the reservoir.
Core descriptions and unsuccessful completion attempts indicate a dense serpentine of low porosity around the edges of the plug. Core analysis data are, therefore, not necessarily representative of the average rock properties throughout the reservoir. There are 45,746 acre-ft of serpentine present in this reservoir above the water-oil contact. Volumetric balance calculations indicate an original oil in place of 13,128,400 reservoir bbl. With an estimated average connate water saturation of 20 per cent, an average porosity of 4.6 per cent would be required to contain this amount of oil within the serpentine volume mentioned above. There is good pressure continuity between wells in spite of disproportionate withdrawals from the producing wells, and it is believed that all of the reservoir has been subject to drainage and that the average effective porosity is 4.6 per cent. Table 1 outlines pertinent data for this reservoir.