Tunu is one of Mahakam fields with majority gas production. The depositional nature of fluvial with minimum tidal influence results in the signature of delta sedimentation by hundred layers of gas-bearing sand lenses as pay zone. They are constructed of unconsolidated clean and shaly sand reservoirs at the shallower burial and higher consolidation at deeper burial due to compaction and diagenesis. The unconsolidated section requires sand control as mandatory means to unlock it safely. The combined challenge of numerous sand layers and marginal reserves makes it economically impossible to perform regular detailed physical sand grain assessment by individual conventional coring completed with Laser Particle Sieve Analysis (LPSA). An economic approach is through performing sand bailing. However, the bailed sand dry-sieve results were confusing with wide particle size distribution (PSD) curve variation from several well samples. Referring to this PSD uncertainty, installing straddled thru-tubing screen in front of the reservoir as sand control resulted in good production and plugged indication at the beginning of the initiative by utilizing a similar screen opening size. Thus, a new fit-for-purpose methodology was required. A study to predict sand grain size on each reservoir target was initiated by analyzing three available shallow reservoir cores in Mahakam, which could cover most of Tunu's shallow sedimentation type. The result was that most of the sand grain size distribution on each sample core correlated with their calculated shale volume content (v-shale). Lower v-shale is respected to larger sand grain size. Unconsolidated Tunu Shallow reservoir doesn't contain any specific radioactive minerals. Thus, v-shale could be easily calculated from gamma-ray logs, which are always available on each reservoir target at any drilled wells. The relationship between sand grain size and v-shale was gathered on a single map. The map was then validated by historical screen installation. Positive results were seen when screen size selection respects specific patterns on the generated sand map at the v-shale value of perforation intervals. Thru-tubing screen installation campaign was continued following the new sand map reference. It could deliver more than 80% successful installation with no plugging or sand at a new perforated reservoir when no screen integrity issue due to erosion was encountered. This novel approach allowed better prediction of thru-tubing screen opening size requirements and perforation interval selection in Tunu unconsolidated reservoir and was successfully expanded in offshore Mahakam field at similar facies.

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractThe Elemental Capture Spectroscopy (ECS) log measures the concentrations of a number of elements (Al, and Ti) in the formation by neutron capture spectroscopy. These are used to compute mass fractions of certain components of the formation (clay, quartzfeldspar-micas, coal and carbonate). This log was recorded in a cored well of a large field in a deltaic environment with a view to checking the routine interpretation model of triplecombo logs.

Tambora Field reservoir zone is sub-divided into D, E, F and G. Of the four zonation, Tambora G Zone has the lowest recovery factor. Based on this, the current study was intended to have better understanding of the diagenetic processes in low productivity reservoirs and its development strategy in that zone. Reduction of porosity and permeability due to different diagenetic intensity and causes are possible reasons for this condition. A new-improved petrology study was performed to understand the effects of diagenesis and the contribution of clay minerals which has led to worsening reservoir characteristics. In order to achieve better understanding of reservoir characteristics, integrated petrology analysis of petrography, XRD, SEM and CEC were performed. The results of detailed lithofacies analyses show that low productivity related to poor porosity and permeability is primarily caused by mechanical compaction and are worsened by chemical diagenesis related to isolated pore spaces, unconnected pore throats and depositional environment. Those affects the increase of diagenetic quartz-overgrowths, ferroan/iron-bearing and calcareous minerals. The occurrence of these minerals act as a pore-filling cement and are more developed in clean rather than shaly Sandstones. The most dominant diagenetic clay mineral in all lithofacies is recorded as kaolinite, followed by illite, chlorite and illite-smectite with this trend varying relative to depth and lithofacies. The effect of these factors is more intense when burial depth increases, and the depositional environment is increasingly distal as in the G Zone’s northeast area. Referring to this, and in order to minimize the risks of diagenetic minerals causing low productivity, the well placement strategy is addressed to the south and northwest compared to the northeast area. The proven result of applying this approach is the success story of drilling the TM-132 northwest well in 2019 that reached an initial gas rate production of around 3 MMscfd.

No abstract