Representative fluid samples are essential to achieving high quality PVT and flow assurance lab analyses. This is especially important when downhole samples are acquired in an oil base mud (OBM) environment. These high quality samples are also needed to better understand reservoir and fluid behavior throughout the field life.This work presents a case study of an offshore field in East Asia that required high quality reservoir oil fluid samples for detailed PVT and flow assurance analyses. An oil bearing sand was discovered during the development drilling phase of a predominantly gas bearing reservoir environment. It was required to take low contamination samples from this zone during the development drilling phase without compromising the primary well objective of completion as a gas producer. As such, samples had to be taken on wireline in an oil based mud (OBM) environment. Accordingly a carefully planned methodology and technology was planned and used to achieve the goal of obtaining reservoir fluid samples.Samples acquired from a previous well in the field using traditional openhole wireline formation testing technology and methods resulted in relatively high contamination levels. High levels of OBM filtrate contamination typically have detrimental effects on the PVT analyses quality for both gas and oil samples. Rig time, cost and sticking risk also limited the time allowed for the wireline formation tester to stay stationary at a sampling depth. As a result, a decision was made to utilize a new sampling technology, Quicksilver, that is specifically designed to obtain low level contamination samples while minimizing sampling station and hence rig time. To achieve this goal, the job was carefully designed and monitored by operating company and service company experts in real time to ensure the required results. The sampling technology, method and field and laboratory results are presented in this work.

Kikeh Field is a deepwater project located in Malaysia. The development plan for this field requires fifteen water injectors, eighteen producers, and one gas injector to be completed in more than 4,300 ft of water depth. In order to maintain the oil production target for this field, the water injection rate should double the target oil rate. To achieve this, water must be injected into the formation at fracturing pressures.The completion campaign started with three water injector wells. The initial results were not as expected, i.e. after pumping 1000 bbls of treated seawater at rates from 7 to 14.5 bpm, surface pressures were still within the pressure limit of 3000 psi, given by the Floating Production Storage and Offloading (FPSO) facilities. However, the injection rate was decreased with increase in pressure, and skin factor was found to be increased. Another observation was that the formation was not fractured at pressures exceeding the expected closure stress.Possible explanations for such behaviour were: (1) the development of a "temperature" sensitive emulsion in the reservoir matrix, (2) the effect of temperature in viscosity of our seawater crude, (3) near wellbore damage caused by fines from the injected water blocking the near wellbore region.When a second injectivity test on the second well was conducted, again the injected rate was not able to create fracture even though the injected pressure was above the breakdown pressure. After analyzing the injectivity data, another mechanism related to poroelastic stress was postulated. Poroelastic stress is a transient localized stress increase caused by fluid injection into porous media.Possible explanations have been looked in details using pressure transient data and it supports the theory of poroelastic effect. Then the remedial action was selected to overcome poroelastic behaviour in the Kikeh field. The operation procedure and the result obtained after injecting Viscoelastic fluids at fracturing rates are discussed in this paper. This paper also describes the evaluation of skin after each injectivity test from pressure transient analysis.

The acquisition of high quality reservoir information in exploration campaigns is a continuous challenge in today's operations. The operational risks, time, cost, environmental concerns and reservoirs complexities are several important factors to be considered in reservoir characterization planning. Key reservoir information includes fluid types and composition, horizontal permeability, vertical permeability, damage skin, radius of investigation and reservoir pressure.This work presents the reservoir evaluation done in the basement with the mobility range of 0.01 to 0.09 mD/cP in an offshore Malaysia oil field. An early and quick identification of hydrocarbon prospect was required for appraisal wells planning. The expected low mobility in basement complicates the exploration data acquisition. Conventional reservoir fluid characterization through bottom hole sampling and PVT lab analysis is proven to be ineffective due to the long waiting time before the results are available. Full scale DST on the other hands offers higher operational complexity and cost for reservoir parameters determination.As an alternative, the wireline formation tester dual packer module was deployed to perform a DST like testing known as interval pressure transient test (IPTT). At the interval of interests with the presence of hydrocarbon, the dual packer module offers selectively straddling reservoir sections to provide the capability to conduct controlled local production and interference for reservoir parameters estimation through pressure transient analysis. Downhole fluid analysis was performed to provide the reservoir fluid properties input. By providing larger flow area also, dual packer module enables the reservoir characterization in the low mobility intervals through downhole fluid analysis and IPTT techniques. The examples of IPTT applications in oil reservoirs and the analysis methodology will be presented in this paper.

Formation pressure and mobility measurements play a critical role in the development and management of compartmentalized reservoirs. Conventionally, wireline formation tester (WFT) tool has been used for such appliations. However, reservoir evaluation becomes challenging in high temperature environment, due to the unchangeable temperature limitations of WFT tools.This paper presents a case study where formation pressure and mobility are acquired by applying formation pressure testing while drilling (FPWD) at a high temperature (HT) offshore gas well in South Sea, China. With a thermal gradient of as high as 4.5 degC/100m, the estimated formation temperature is higher than the maximum temperature rating of the wireline tools. By integrating detailed pre-job design maintaining the working temperature at acceptable range and real-time monitoring including data quality control and measurement optimization ensuring the functionality of hardware and the quality of measurement, FPWD has successfully revealed the formation properties.

Reservoir pressure is one of the key properties needed in formation characterization. In addition to reservoir fluid identification through pressure gradient, reservoir pressure measurement plays a vital role in evaluating reservoir connectivity. This understanding of reservoir connectivity will subsequently aid in reservoir management planning, including completion design optimization. Formation connectivity investigation is especially challenging in a cased-hole environment where unfavorable wellbore conditions prevented open-hole evaluations. This paper presents a case study in a Malaysia offshore field where formation pressure measurements behind casing were carried out to allow the investigation of formation connectivity which is required for completion design, production planning, and potential cross-flow for zone commingling strategies. Cased-hole formation tester was used to evaluate formation pressure in the target zones where two wells were drilled in the same field. The formation pressure acquired was subsequently utilized in completion design and perforation planning based on reservoir connectivity. The pertinent questions about this field have been answered and helped in making the best possible connection between the wellbore and production optimization. This application of formation pressure measurement behind casing has been proven to add value to the completion design optimization process. Lessons learned supported by field data will be presented along with recommended cased-hole reservoir connectivity investigation techniques and strategy.