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This paper examines the profitability of past waterflood infill drilling programs. The project data is from the Texas Railroad Commission files, and includes large carbonate and sandstone reservoirs such as the Wasson (San Andres) Field and the Big Wells (San Miguel) Field. All of the reservoirs were subject of intensive reservoir engineering and geologic study by the oil companies prior to initiation of the infill drilling project. The permeability of the reservoirs averages 8.8 md and ranges from .65 md to 27 md. The porosity averages 10% and ranges from 7% to 18.6%. The depths range from 1220 to 1525 meters with the deepest at 2130 meters.
Because of the large capital cost required for drilling and operating additional wells, it was not clear whether the infill drilling programs had recovered enough additional oil to be good investments. In spite of the variability of external factors such as the cost of wells and price of oil, all of the projects studied obtained at least an acceptable economic return. the average discounted profit to investment ratio was 2.0, and the average incremental oil per well was 15 thousand cubic meters. Most of the calculated rates of return exceeded 30%. The net present value at 15% after taxes ranged from $580,000 to $32 million dollars. Thus these waterflood infill drilling projects have generally been very successful.
Infill drilling can be defined as the drilling of additional wells in a field that has already completed primary production. Due to early industry troubles and poor practices relating to well spacing, many large fields in Texas were originally drilled under well spacing regulation by the Texas Railroad Commission. The principle objectives of these regulations were to: 1) prevent waste and 2) prevent misappropriation of property. The first of these objectives originally referred to the excess of production over demand as being waste, but has cane to mean "maximize recovery of hydrocarbons" to prevent the waste of leaving them in the ground. This objective gave rise to production rationing and allowables. The second objective was to minimize oil migration across lease lines, because operators were opposed to compulsory unitization. This created the need for spacing rules so that operators could not line wells up along the lease lines and attempt to drain the neighbor's property. There were some crude attempts to optimize well spacing for primary production, but in the end, it was somewhat arbitrarily decided that all fields would be developed according to the Statewide spacing rules. This led to a preponderance of fields with 16.2 ha/well spacing, and many with 32.4 and 64.8 ha/well spacings. The wider spacings were sought for greater depth, less pay, and other factors directly affecting the economics. The final result is that many fields in Texas were originally drilled by field rules intended for orderly primary recovery.
Well spacing has generated considerable controversy over the years. Early operators had generally recognized that drilling a great number of wells would not proportionally increase ultimate (primary) recovery. Over-drilling only resulted in excessive capital costs and lowered the return on the investment. This is the main position taken by managers that believe infill drilling only results in acceleration of production and does not produce new reserves. Whether this is true or not is largely irrelevant if maximizing the value of the company is the main criteria for selecting projects.
This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 91755, "Fast Method Finds Infill-Drilling Potentials in Mature Tight Reservoirs," by L. Guan, SPE, Texas A&M U., and Y. Du, SPE, New Mexico Inst. of Mining and Technology, prepared for the 2004 SPE International Petroleum Conference in Mexico, Puebla, Mexico, 8-9 November.
Abstract The subject field is a highly heterogeneous giant offshore reservoir. Current field development is predicated upon line drive water injection with 1 km spacing; however, it is anticipated that some oil will be bypassed due to geologic heterogeneity. In order to address the bypassed oil and improve recovery, a simulation study evaluating infill well potential for the target reservoir and an optimization of the full field development plan with infills was carried out. This reservoir consists of two geologically similar areas which are a "Homogeneous" area and a "Heterogeneous" area. High permeability streaks (HKS) having ten times higher permeability than the matrix permeability are dominant in the Heterogeneous area while HKS are significantly less prevalent in the Homogeneous area. Two sector models which represent the Heterogeneous and the Homogeneous areas were generated and sensitivity simulations were carried out to evaluate the vertical and lateral placement of infills. Based on sector model findings, full field simulations were carried out to generate an optimized full field development plan with infills. As a result of sector model simulation for the Heterogeneous area, infill wells showed higher recovery relative to the "No Infill" base case. Vertical and lateral well placement on infill location had little impact on the oil recovery. This is because the HKS in the upper layers were water-saturated by historical water injection from the base 1 km development; hence, water breakthrough at infill wells occurred from HKS within a short period of time wherever infills were drilled. For the Homogeneous area, infill wells showed slightly higher recovery but no oil plateau extension and high water production relative to the "No Infill" base case. Based on these findings it was concluded that (i) infills were required for Heterogeneous area and (ii) infill are not recommended for the Homogeneous area. For the full field evaluation, three different infill scenarios (i.e. 500m spacing infill implementation, 375m spacing infill implementation and no-infill implementation) were evaluated. The optimal infill development scheme for each pattern was chosen by comparing the production performance of each pattern of these three simulations. As a result, in the optimized infill case, infill wells were required primarily in the Heterogeneous area and were not required for the Homogeneous area. Through this analysis, the impact of geological heterogeneity on the performance of infill wells and incremental oil recovery was assessed and the full field development plan was significantly improved. Based on these findings the resulting full-field development plan (i) minimizes the number of infill wells required, (ii) optimizes incremental oil production by addressing the bypassed oil.
Abstract This paper describes an integrated asset modeling program designed to determine reserves that can be drained by an infill prospect within a mature asset. This model has proven its ability to reduce risks and improve reservoir decline management. It is able to quickly identify potential benefits of drilling without spending significant time building complex reservoir simulation models. The West Java fields, operated by BP Indonesia, are located in the northwestern part of the Java Island. Production commenced in 1971 on these mature offshore assets with interdependent oil and gas systems. Over 50 separate reservoirs have been identified in these highly stratified structures and many wells produce hydrocarbon from multiple horizons (commingled production). The surface facility network is very complex integrating many producers, various production/compression systems and long pipeline sections. As the fields become mature then there is an increasing need to drill more and more wells to recover untapped reserves and reduce production decline. Quick screenings are required to identify the possibility of drilling an infill well surrounding the existing producers or to access untapped hydrocarbon reserves. An integrated model connecting reservoir tanks, wells, pipeline networks and surface facilities was build support the infill decision. The model can handle naturally flowing, gas lifted and ESPed producing wells. There is no limit on number of wells and/or platforms that can be analyzed. Constraints can be considered at all levels, from well, joint, separator and the overall system. Moreover, production forecasting from the model can also accommodate constraints at the reservoir level. Background The BP Indonesia ONWJ contract area is located offshore of the northern coast of the island of Java (see Fig. 1) and stretches at a distance of 50 miles from the shoreline. The first exploration well was drilled in 1967 and first production started in 1971. The production facility is comprised of 13 flowstations, 150 production and 40 processing platforms, 700 wells with 1,013 production strings and service facilities. More than 1,000 miles of pipeline interconnect the production facilities. The field currently produces around 35,000 BOPD with 300 BBTUD of gas. There are some custody transfer points provided to deliver product to the customer. To fulfill BP's commitment supporting gas deliveries to the Java market, a series of development studies have been undertaken to assess infill opportunities in the gas reservoirs. Cost effective infill drilling was identified as the most economic means to maintain production. The major uncertainties which influence the ability to identify infill gas development opportunities are complex geology, extensive faulting and internal crossflow. This paper presents a case study that demonstrates the use of an integrated asset model to assist engineering decisions in reservoir development. An integrated asset modeling program was selected to give a quick solution to identify the benefits of drilling an infill well instead of building a complex reservoir simulation model that is very time consuming to run. The integrated asset model can accommodate more than five gas reservoirs and can simulate commingled production as one of the production strategies. Moreover, the model could alert the engineering teams about the crossflow possibility among producing zones. Integrated Asset Modeling A variety of reservoir modeling technologies are employed to address various issues concerning field development and the assessment of oil and gas reserves. Integrated Asset Modeling software models complete production system from reservoir to surface network. The model consists of three applications which are integrated in one toolkit:A reservoir engineering modeling tool based on material balance equations. It helps engineers define reservoir drive mechanisms and hydrocarbon volumes in place; A well performance, design and optimization program. It is designed to allow the building of reliable and consistent well models, with the ability to address each aspect of wellbore modeling, fluid characterization, VLP correlations and IPR (reservoir inflow); A production network optimization program to model the gathering-pipeline system and facility network. It is a multiphase optimizer of the surface networks which is linked to reservoir and well models.