This paper will detail how a mature oil field in the South Kalimantan region of Indonesia was revitalised by the use of hydraulic fracturing. The Tanjung Raya field is a complex, multilayered, mature oil field. This field was initially developed in the 1960's, with production peaking at over 55,000 bopd. By the mid 1990's, production had declined to less than 1,200 bopd. The introduction of a water flood increased production to a peak of 10,000 bopd, but this quickly declined at an average rate of circa 33% per year. With the introduction of a fracturing programme, based on treating existing and new wells, production has been maintained at a flat 7,000 bopd over the past two years. The hydraulic fracturing program has accounted for 80% of these significant production gains, adding more than 5.7 million barrels of recoverable reserves and extending the economic life of the field by more than 2.5 years. Hydraulic fracturing is a process that is relatively underutilised in the Asia-Pacific region, as compared to North America, Latin America and the Middle East. With a couple of recent noticeable exceptions, the technique is either not considered during field development and redevelopment, or it is used on a one-off, remedial basis. However, fracturing can be an integral part of well design, and an effective tool when the technique is applied systematically by practitioners who understand its capabilities; as demonstrated in the Tanjung Raya field. This paper will discuss how a significant increase in oil productivity from a mature field was attained with a very high propped fracture treatment success rate. It will also detail how the correct design of fracture treatments can enhance reservoir recovery rates, and fully utilise vertical wells as a low cost, effective alternative to horizontal wells, or to increase well spacing. The paper will also discuss the most significant issues of implementing such a program and how these issues were effectively dealt with in the Tanjung field. Introduction Description of Field The Tanjung structure is located in the northeastern Barito basin in the Southeast corner of Kalimantan (Indonesian Borneo), as illustrated in Figure 1. The structure is a large, NS to NNE-SSW oriented, asymmetric faulted anticline, bounded on the west and north by a high-angle major thrust-fault with about 1500m of throw. The approximate dimension of the Tanjung structure is 9 km long and 3 km wide. The field covers an area of about 4000 acres. The Tanjung structure is a very late stage Plio-Pleistocene and is originally a normally faulted structural low, with a thick development of Tanjung formation. During the late Miocene and Pliocene, the Barito basin was subjected to a major phase of compression, thrust faulting, anticlinal folding, and strike slip faulting. This tectonic activity created most of the present day structures in the Barito basin, including Tanjung (see Appendix 1 for structural maps, Figures 8, 9 and 10).

The Valdemar Field is located in the Danish North Sea sector with the target reservoir being a Lower Cretaceous "dirty chalk" containing up to 25% insoluble fines, >20% porosity and permeability below 0.5 mD. The formation will not produce commercial quantities of oil without stimulation and it has been shown through laboratory core experiments as well as field trials that acid fracturing does not maintain conductivity as effectively as propped fractures. The initial reservoir pressure is above seawater hydrostatic and the reservoir thickness ranges from ten to several hundred feet. The Lower Cretaceous Chalk is found below the typical Ekofisk and Tor formations, which have been the target horizon in the North Sea for over four decades. Valdemar has been successfully developed with extended reach horizontal wells but, in order to establish economic production rates, all wells must be stimulated as part of the initial completion. In a typical Valdemar well, a 16,000 ft long lateral is drilled, with the toe of the well completed with a limited entry, predrilled liner, while the upper 10,000 ft of lateral, which is within coiled tubing reach, is completed with 12 - 14 propped fracture stages. Traditional designs revolved around placing 500,000 to 1,000,000 lb of 20/40 natural sand per stage. Consequently, very large volumes of proppant had to be handled during the completion, creating a logistics challenge, more so in an offshore environment where proppant available on location is limited to the capacity of the stimulation vessel. Stimulations on several wells showed suboptimal production rates which led to the conclusion that the Lower Cretaceous was not economically producible. An intensive study was carried out to evaluate all aspects of the fracture design and implementation which resulted in 11 key findings comprising pumping schedule, fracture fluid design, proppant selection and flowback control, completion hardware, QA/QC during the fracture execution and well cleanup, data acquisition for real-time monitoring and "after-closure" analysis. This paper focuses on the aspects of proppant selection and adequate fracture conductivity placement, with the goal of improving well productivity and cumulative recovery. Reservoir simulation advised that replacing natural sand by a larger, lightweight ceramic proppant could result in reducing proppant volumes by up to 50% while improving productivity by 20 to 50%. By reducing the proppant volume, the stimulation vessel port calls to load materials for multistage treatments could potentially be reduced resulting in significant savings. This was deemed a critical factor for future offshore multistage fracture completions which could benefit significantly from reduced roundtrips in terms of time, cost and early production. The recommendations of the optimization program were implemented in two wells. PLT results confirmed the predictions, that despite the total proppant volume being cut by 50%, the zonal contribution of the ceramic stimulated zones was better than that of natural sand in all cases. The higher fracture conductivity obtained with the ceramic proppant, even using one half the sand mass, resulted in improved productivity by some 50%. These completion optimization measures allowed for the successful development in the flank wells that might have otherwise been deemed uneconomic.

There has been a considerable number of matrix acid stimulation treatments performed in high porosity -low permeability chalk reservoirs in the Danish part of North Sea over the last four decades. During this time, several acid types and diversion techniques have been employed to obtain a desired fluid distribution without the ability to measure the actual success of this distribution. The typical references to design such treatments were based on the knowledge of carbonate dissolution reaction by acid, lab scale core testing and reference outputs of matrix acid model simulators 1 . Limited work has been carried out to capture actual dissolution behavior and distribution down the well. This includes understanding both acid-diversion efficiency and production contribution for complex and extended reach intervals.The implementation of Distributed Temperature Sensing (DTS) and Zonal Downhole Gauges as part of the lower completion in one complex, newly drilled well, has enabled the possibility of monitoring real time temperature profiles along the wellbore allowing determination of flow distribution both before and after an acid and diverter stage enters the formation 2 . Realizing the effects of acid and diverters will lead to a better understanding of the chemistry, reaction and diversion process, and subsequently to the optimization of future designs. Fluid flow path and zonal isolation was also monitored during the treatment which provided insights into mechanical issues with respect to tubing, packer, cement and wellbore integrity. In addition to the real-time data gathered during the execution of the treatment, considerable knowledge of post stimulation zonal production contribution was afforded for both production and stimulation modeling.This paper discusses the benefits, challenges, execution and findings of a complicated application of both DTS and zonal gauges for matrix acidizing treatments and production characterization on an Ekofisk chalk formation. The primary stimulation and the subsequent re-stimulation was executed in opposite ends of the perforated interval with DTS being recorded prior to and after the stimulation fluid was pumped. The captured lessons learned will be an invaluable reference for future acid stimulation treatments of Danish chalk in the North Sea.